S-2/A 1 d78066a1s-2a.txt PRE-EFFECTIVE AMENDMENT NO. 1 TO FORM S-2 1 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OCTOBER 6, 2000 REGISTRATION NO. 333-41992 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- PRE-EFFECTIVE AMENDMENT NO. 1 TO FORM S-2 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 --------------------- DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) (Exact name of registrant as specified in its charter) DELAWARE 1311 75-2615565 (State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer incorporation or organization) Classification Code Numbers) Identification No.)
--------------------- 13760 NOEL ROAD, SUITE 1030 DALLAS, TEXAS 75240-7336 (972) 233-9906 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) --------------------- ROBERT P. LINDSAY CHIEF OPERATING OFFICER 13760 NOEL ROAD, SUITE 1030 DALLAS, TEXAS 75240-7336 TELEPHONE: (972) 233-9906 FAX: (972) 233-9575 (Name, address, including zip code, and telephone number, including area code, of agent for service) --------------------- Copies to: WILLIAM L. BOEING KENNETH L. STEWART HAYNES AND BOONE, LLP FULBRIGHT & JAWORSKI L.L.P. 1600 N. COLLINS BLVD., SUITE 2000 2200 ROSS AVENUE, SUITE 2800 RICHARDSON, TEXAS 75080 DALLAS, TEXAS 75201 TELEPHONE: (972) 680-7550 TELEPHONE: (214) 855-8000 FAX: (972) 680-7551 FAX: (214) 855-8200
--------------------- APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after the effective date of this Registration Statement. If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. [ ] If the registrant elects to deliver its latest annual report to security holders, or a complete and legal facsimile thereof, pursuant to Item 11(a)(1) of this Form, check the following box. [ ] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following box. [ ] THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 2 The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. SUBJECT TO COMPLETION, DATED OCTOBER 6, 2000 PROSPECTUS 10,000,000 SHARES [DEVX ENERGY LOGO] COMMON STOCK --------------------- We are selling 10,000,000 shares of our common stock. This is an initial public offering of our common stock. Our common stock is quoted on the OTC Bulletin Board under the symbol "QSRI." Although our common stock is quoted on the OTC Bulletin Board, the public offering price of the common stock in this offering is not based on the market price of our common stock but was determined by negotiations between us and the underwriters based on factors described in "Underwriting." It is currently estimated that the public offering price per share will be between $7.00 and $9.00. We have filed an application to designate our common stock on the Nasdaq National Market subject to issuance. We cannot assure you that we will be able to designate our common stock on the Nasdaq National Market. You should read this prospectus carefully before you invest.
PER SHARE TOTAL ----------- ----------- Public offering price....................................... $ $ Underwriting discounts and commissions...................... $ $ Proceeds, before expenses, to us............................ $ $
The underwriters may purchase up to an additional 1,500,000 shares of common stock from us at the public offering price less the underwriting discount, to cover over-allotments. The underwriters expect to deliver the shares against payment in Arlington, Virginia on or about , 2000. YOU SHOULD READ THE SECTION ENTITLED "RISK FACTORS" BEGINNING ON PAGE 10 FOR A DISCUSSION OF CERTAIN FACTORS YOU SHOULD CONSIDER BEFORE BUYING OUR COMMON STOCK. NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. FRIEDMAN BILLINGS RAMSEY STIFEL, NICOLAUS & COMPANY, INCORPORATED PROSPECTUS DATED , 2000 3 [map of the United States with the Company's name and the following areas highlighted: the Appalachian Basin, the Mid-Continent, east Texas, the Gulf Coast, the Permian Basis and south Texas] 2 4 SUMMARY This summary highlights selected information from this prospectus. This summary is not complete and may not contain all of the information that you should consider before investing in our common stock. You should carefully read the entire prospectus before making an investment decision. Unless otherwise indicated, this prospectus reflects no exercise of the underwriters' over-allotment option. Unless otherwise indicated, this prospectus assumes that the recapitalization described below, including the reverse stock split of every 156 outstanding shares of common stock into one share, has occurred. We have provided definitions for some of the oil and gas industry terms used in this prospectus in the "Glossary" beginning on page 72. In this prospectus, we refer to DevX Energy, Inc. and its subsidiaries as "DevX," "we," "our" or "our company." Our fiscal year end is June 30. We recently changed our name from "Queen Sand Resources, Inc." to "DevX Energy, Inc." THE COMPANY We are an independent energy company engaged in the exploration, development, exploitation and acquisition of on-shore oil and natural gas properties in conventional producing areas of North America. To date, we have grown almost exclusively through acquisitions of properties. As a result of our acquisitions we own a diverse property base concentrated in six producing areas or basins. Approximately 58% 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 June 30, 2000, we owned proved reserves of approximately 133 Bcf of natural gas and 2 MMBbls of oil aggregating to approximately 145 Bcfe with an SEC PV-10 value of $217 million and a reserve life index of 12.1 years. Approximately 68% of our proved reserves were classified as proved developed and approximately 92% of our proved reserves were natural gas. Our average daily net production for the three months ending June 30, 2000, was 31.0 MMcfe. At June 30, 2000, we had interests in 667 wells, including 83 service wells. Assuming completion of the recapitalization described below and this offering, we expect to be able to execute an annual capital expenditure program of approximately $20 million. As part of this program, we plan to increase our exploration expenditures and are currently having discussions with potential exploration joint venture partners. We expect our cash flow to increase as a result of the $10.9 million decrease in annual interest expense that we anticipate from the completion of the recapitalization. Upon completion of this offering, the indenture governing our 12 1/2% senior notes will be amended to allow us to increase the level of permitted borrowings under our credit facility to $60 million. We anticipate that we can fund our capital expenditure program through a combination of working capital, operating cash flow and additional borrowings under our credit facility. 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. BUSINESS STRATEGY Our goal is to enhance stockholder value by expanding our oil and natural gas reserves, production levels and cash flow. Our strategy to achieve these goals consists of these elements: - Recapitalizing the company through a significant reduction of debt, a corresponding increase of equity and the elimination of all preferred securities; - Pursuing managed asset growth through: - actively developing and exploiting our existing higher-potential oil and natural gas properties, particularly in south and east Texas; 3 5 - 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; - an increased emphasis on exploration activities; and - targeted merger(s) where the consolidation with other companies will give us access to quality reserves within our core areas; - Maintaining a capital and financial structure with a prudent debt to equity ratio that will allow us to use cash generated from operations to fund growth in our production and reserves; and - Enhancing our board of directors and management team through the addition of new industry senior executives to assist the company in improving and expanding its operating capacity and exploration activities. THE RECAPITALIZATION. Simultaneously with the closing of this offering, we will complete a recapitalization which includes: (a) a reverse stock split of every 156 outstanding shares of our common stock into one share; (b) the exchange of all preferred stock, all warrants exercisable for shares of common stock and all remaining 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 12 1/2% senior notes for approximately $52.5 million. At our stockholders meeting on September 18, 2000, our stockholders approved the first two elements of the recapitalization. The repurchase of our 12 1/2% senior notes does not require stockholder approval. When the recapitalization and this offering are complete, our company will: - recognize a gain on the repurchase of $75 million of our senior notes at a discount, thereby creating more than $21 million of additional equity value for our stockholders; - on a pro forma basis, reduce our debt by approximately $93.5 million, thereby increasing annual cash flow available to fund growth by $10.9 million and reducing our interest cost per Mcfe by nearly 60%; - reduce our long-term debt to $50 million, which approximates 23% of our June 30, 2000 SEC PV-10 of $217 million; - eliminate all outstanding preferred stock; - eliminate the dilutive effects of current market price conversion and repricing rights held by some of our stockholders; - improve our liquidity by using a portion of the proceeds from this offering to pay down our senior working capital facility and modifying the indenture governing our senior notes to permit us to increase our senior working capital facility from $35 million to $60 million; and - be in a position to satisfy the listing requirements of the Nasdaq National Market with a goal of improving the visibility and liquidity of our common stock. Upon completion of the recapitalization and this offering, there will be outstanding 11,250,000 shares of our common stock, no shares of preferred stock and no repricing rights. The closing of this offering is a condition to the completion of the recapitalization, and the completion of the recapitalization is a condition to the completion of this offering. DEVELOPMENT AND EXPLOITATION OF EXISTING PROPERTIES. We have identified over 400 potential 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 and grow our reserves while maximizing the long-term return on our capital. Our opportunities include: - additional exploration of well-defined locations on existing properties such as in the J.C. Martin field in south Texas; - infill drilling on our producing properties such as in the Gilmer field in east Texas; 4 6 - recompletion of existing wells in behind-pipe intervals such as in the Lopeno/Volpe field in south Texas; and - developing proved undeveloped reserves by drilling low risk, long lived natural gas wells in the shallow New Albany Shale formation in Kentucky. PROPERTY ACQUISITIONS AND DIVESTITURES. We will diligently pursue 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. Our focus will be on only those properties that can be acquired at prices that will enhance our overall return on capital. Although we are currently weighted towards natural gas reserves, we anticipate that we may return to a more even oil to natural gas ratio. 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 return on capital. In order to diversify our exposure, we generally acquire larger interests in company-operated, lower risk projects and smaller interests in higher risk/high impact potential 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. If we complete the recapitalization, we expect to be able to attract other small capitalization oil and natural gas companies as merger or consolidation partners as a result of our substantially deleveraged balance sheet and stronger cash flow. We will be in an excellent position to make accretive acquisitions of other companies and, through this process, to use our strong balance sheet and cash flow to effect the recapitalization of suitable merger candidates that otherwise may not have access to capital. CAPITAL AND FINANCIAL STRUCTURE. Our objective is to use a portion of the net proceeds of this offering and internally generated cash flow to fund our exploration, development and exploitation programs. We believe that we can finance our acquisition opportunities at attractive prices with a combination of equity and debt. MANAGEMENT TEAM. With the completion of the recapitalization, we will have the financial capability to pursue our strategy of increased focus on operating those properties that we own and on exploration as a means to grow our assets. We intend to continue restructuring our management team to add to our engineering, geology and geophysical personnel. We also intend to add seasoned senior oil and gas industry executives with experience in building stockholder value and in the management of exploration and development projects. On October 6, 2000, Joseph T. Williams became a director and Chairman of the Board of our company. In addition, we expect that Jerry B. Davis and Robert L. Keiser will join our board of directors before the completion of the recapitalization and this offering. Biographical information for each of Messrs. Williams, Davis and Keiser is included in "Management." Messrs. Williams, Davis and Keiser have informed us that if we do not successfully complete either this public offering of common stock or other acceptable financing arrangements, they will resign from their positions with our company. We are also in the process of recruiting one additional outside, non-employee director whom we expect will join our board of directors within 90 days after the completion of the recapitalization and this offering. As part of the restructuring of our management team, Bruce I. Benn and Robert P. Lindsay will resign from our board of directors immediately following the successful completion of this offering. 5 7 THE OFFERING Common stock offered....... 10,000,000 shares(1) Common stock to be outstanding after this offering................. 11,250,000 shares(2) Use of proceeds............ To repurchase $75 million in aggregate principal amount of our 12 1/2% senior notes for approximately $52.5 million, to repay approximately $14 million outstanding under our credit agreement as of September 30, 2000 and the balance for future acquisitions and other general corporate working capital purposes. OTC Bulletin Board Symbol..................... QSRI --------------- (1) 11,500,000 shares if the underwriters' over-allotment option is exercised in full. (2) 12,750,000 shares if the underwriters' over-allotment is exercised in full. Includes the 1,250,000 shares to be issued in the recapitalization. 6 8 SUMMARY CONSOLIDATED FINANCIAL INFORMATION The following table presents some of our historical and unaudited pro forma consolidated financial data. We completed significant acquisitions of producing oil and natural gas properties during fiscal 1998, which affects the comparability of the historical financial and operating data for the periods presented. The financial data for the three years ended June 30, 2000 are derived from our audited consolidated financial statements. The pro forma financial data are derived from our pro forma financial statements. The financial data are not necessarily indicative of our future performance. You should read the following data in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," our consolidated financial statements and the notes to those financial statements as well as the "Unaudited Pro Forma Condensed Consolidated Financial Statements" included elsewhere in this prospectus.
HISTORICAL PRO FORMA ----------------------------- ---------- YEAR ENDED JUNE 30, YEAR ENDED ----------------------------- JUNE 30, 1998 1999 2000 2000 -------- -------- ------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) OPERATIONS DATA: Oil and natural gas sales(1)...................... $ 12,665 $ 33,783 $32,584 $32,584 Oil and natural gas production expenses(1)........ 6,333 9,127 7,097 7,097 -------- -------- ------- ------- Net oil and natural gas revenues.................. 6,332 24,656 25,487 25,487 General and administrative expenses............... 2,259 3,534 3,026 3,026 -------- -------- ------- ------- EBITDA(2)......................................... 4,073 21,122 22,461 22,461 Interest and financing costs(3)................... 3,957 17,003 16,945 6,010 Depletion, depreciation, and amortization(4)...... 4,809 13,354 10,259 10,259 Hedge contract termination costs(5)............... -- -- 3,328 3,328 Ceiling test write-down(6)........................ 28,166 35,033 -- -- Interest and other income......................... (105) (326) (143) (143) -------- -------- ------- ------- Net income (loss) before extraordinary item....... (32,754) (43,942) (7,928) $ 3,007 -------- -------- ------- ======= Extraordinary loss(7)............................. -- 3,549 1,130 -------- -------- ------- Net income (loss)................................. $(32,754) $(47,491) $(9,058) ======== ======== ======= Net income (loss) per common share before extraordinary item............................. $ (1.44) $ (1.40) $ (0.18) $ 0.27
HISTORICAL ------------------------------ PRO FORMA AT JUNE 30, ----------- ------------------------------ AT JUNE 30, 1998 1999 2000 2000 -------- -------- -------- ----------- (IN THOUSANDS) BALANCE SHEET DATA (AT END OF PERIOD): Total current assets............................ $ 6,411 $ 14,019 $ 18,524 $ 25,274 Property and equipment, net..................... 142,467 97,198 92,525 92,525 Deferred assets................................. 4,797 7,993 8,144 4,682 Total assets.................................... 153,675 119,210 119,193 122,481 Total current liabilities....................... 6,836 11,142 10,535 5,847 Long-term obligations, net of current portion... 153,619 133,852 143,500 50,000 Total stockholders' equity (deficit)............ (6,780) (25,784) (34,842) 66,634
--------------- (1) Oil and natural gas sales and production expenses related to net profits interests have been presented as if the net profits interests were working interests. Oil and natural gas sales include revenues relating to the net profits interests of $6,219,000 for the year ended June 30, 1998, $29,071,000 for the year ended June 30, 1999, and $28,715,000 for the year ended June 30, 2000. Oil and natural gas production expenses include expenses relating to the net profits interests of $1,787,000 for the year 7 9 ended June 30, 1998, $5,931,000 for the year ended June 30,1999, and $5,725,000 for the year ended June 30, 2000. (2) EBITDA represents earnings before interest expense, income taxes, depreciation, depletion and amortization expense, 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 $22,000 of amortized deferred charges related to our natural gas price hedging program for the year ended June 30, 1998. Depreciation, depletion and amortization for the year ended June 30, 1999 includes amortized deferred charges related to debt obligations of $1.3 million, and $120,000 of amortized deferred charges related to our natural gas price hedging program. Depreciation, depletion and amortization for the year ended June 30, 2000 includes $1,600,000 of amortized deferred charges related to debt obligations, and $98,000 of amortized deferred charges related to our natural gas price hedging program. (5) In conjunction with the execution of our restated credit agreement in October 1999, we terminated the ceiling portion of a natural gas hedging contract at a cost of $3,328,000. (6) In accordance with the full cost method of accounting, the results of operations for the year ended June 30, 1998 include a writedown of oil and natural gas properties of $28,166,000 and for the year ended June 30, 1999 include a writedown of $35,033,000. (7) During July 1998, we terminated a LIBOR interest rate swap agreement at a cost of $3,549,000. During October 1999, we retired borrowings under our old credit agreement and entered into a restated credit agreement with a new lender. As a result, we wrote off $1,130,000 of deferred costs relating to the old credit agreement. 8 10 SUMMARY OPERATING AND RESERVE DATA The following table presents some of our operating and reserve data. You should read the following data in conjunction with "Risk Factors -- Our profitability is highly dependent on the prices for oil and natural gas, which can be extremely volatile," "-- 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," and "Business -- Oil and natural gas reserves" included elsewhere in this prospectus.
YEAR ENDED JUNE 30, -------------------------- 1998 1999 2000 ------ ------- ------- OPERATING DATA: Production volumes: Natural gas (MMcf)........................................ 3,368 12,962 10,618 Oil (MBbl)................................................ 325 500 224 Total (MMcfe)..................................... 5,318 15,960 11,960 Average sales price: Natural gas (per Mcf)..................................... $ 2.27 $ 2.13 $ 2.59 Oil (per Bbl)............................................. 15.52 12.37 22.76 Natural gas equivalent (per Mcfe)......................... 2.39 2.12 2.72 Selected expenses (per Mcfe): Lease operating expense................................... $ 1.07 $ 0.49 $ 0.47 Production taxes.......................................... 0.12 0.09 0.12 General and administrative................................ 0.43 0.22 0.25 Depreciation, depletion and amortization(1)............... 0.89 0.74 0.71 Interest expense.......................................... 0.75 1.06 1.42
AT JUNE 30, ------------------------------ 1998 1999 2000 -------- -------- -------- PROVED RESERVE DATA (END OF PERIOD): Proved reserves: Natural gas (MMcf)..................................... 176,095 137,561 132,680 Oil (MBbl)............................................. 7,949 4,624 2,010 Total (MMcfe)..................................... 223,788 165,299 144,740 Percent of proved developed reserves........................ 68.3% 65.0% 67.4% Percent of natural gas reserves............................. 78.7% 83.2% 91.7% Reserve Life Index (years)(2)............................... 11.4 10.4 12.1 Estimated future net cash flows before income taxes (in thousands)................................................ $318,663 $271,993 $467,036 SEC PV-10 (in thousands).................................... $165,120 $130,726 $217,372
--------------- (1) Represents depreciation, depletion and amortization of oil and natural gas properties only. (2) The Reserve Life Index at June 30, 1998 was calculated using pro forma production of 19,654 MMcfe for the year ended June 30, 1998. 9 11 RISK FACTORS You should carefully consider the following risks before making an investment decision. The trading price of our common stock could decline due to any of these risks, and you could lose all or part of your investment. You also should refer to the other information set forth in this prospectus, including our financial statements and the related notes thereto. 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. Since beginning operations in 1995, we have not been profitable on an annual basis. We experienced a net loss of approximately $32.8 million for the year ended June 30, 1998, a net loss of approximately $47.5 million for the year ended June 30, 1999 and a net loss of approximately $9.1 million for the year ended June 30, 2000. We may experience net losses in the future as we continue to incur significant operating expenses and to make capital expenditures. Even if we do become profitable, we may not sustain or increase profitability on a quarterly or annual basis in the future. At June 30, 2000, we had an accumulated deficit of approximately $92.9 million. 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: - weather conditions; - the level of consumer product demand; - domestic and foreign governmental regulations; - the price and availability of alternative fuels; - political conditions in oil and natural gas producing regions; - the domestic and foreign supply of oil and natural gas; - the availability, proximity and capacity of gathering systems of natural gas; - the price of foreign imports; and - 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 10 12 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: - the other party to the hedging contract defaults on its contract obligations; or - 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 June 30, 2000, our revenues were reduced by approximately $1.5 million as a result of 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 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 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 this offering, 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 $6.6 million under our credit agreement as of October 3, 2000, 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. 11 13 OUR LEVEL OF DEBT MAY NOT ALLOW US PROPERLY TO PLAN FOR FUTURE OPPORTUNITIES OR TO COMPETE EFFECTIVELY. After completion of this offering and the recapitalization, we will have debt of approximately $50 million. As of June 30, 2000, our ratio of total indebtedness to total capitalization was 132% and our consolidated total interest coverage ratio was 1.3 to 1. Assuming the completion of the recapitalization and this offering with net proceeds to us of at least $74 million and the application of the net proceeds of this offering as described in this prospectus, our ratio of total indebtedness to total capitalization would be approximately 45% and our consolidated total interest coverage ratio would be 3.7 to 1. In addition, we may borrow more money in the future to fund our business strategy. This level of debt could: - increase our vulnerability to general adverse economic and industry conditions, especially declines in oil and natural gas prices; - limit our ability to fund future acquisitions, capital expenditures and other general corporate requirements; - require us to dedicate a material portion of our cash flow from operations to payments on our debt; - limit our flexibility in planning for or reacting to, changes in our business and industry; and - limit our ability to, among other things, borrow additional funds, sell assets and pay dividends. 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: - dispose of assets; - incur additional indebtedness; - repay other indebtedness; - pay dividends; - enter into specified investments or acquisitions; - repurchase or redeem capital stock; - merge or consolidate; or - 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 12 14 conditions, including the prices paid for oil and natural gas, success in our exploration, development and exploitation activities, and legislative, 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: - our ability to timely explore, develop and exploit acquired properties; - our ability to continue to attract and retain skilled personnel; - our ability to continue to expand our technical, operational and administrative resources; and - 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: - general economic and industry conditions, including the prices received for oil and natural gas; - mechanical problems encountered in drilling wells or in production activities; - problems in title to our properties; - weather conditions which delay drilling activities or cause producing wells to be shut down; - compliance with governmental requirements; and - 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. 13 15 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: - unusual or unexpected geologic formations; - unanticipated pressures; - mechanical failures; - blowouts where oil or natural gas flows uncontrolled at a wellhead; - cratering or collapse of the formation; - explosions; - pollution; and - 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. OUR SECONDARY RECOVERY PROJECTS REQUIRE SIGNIFICANT CAPITAL EXPENDITURES AND MAY NOT BE COMMERCIALLY SUCCESSFUL. We face the risk that we will spend a significant amount of money on secondary recovery operations, such as waterflooding projects, without any increase in production. Although waterflooding requires significant capital expenditures, the total amount of reserves that can be recovered though waterflooding is uncertain. In addition, there is generally a delay between the initiation of water injection into a formation containing hydrocarbons and any increase in production that may result from the injection. The degree of success, if any, of any secondary recovery program depends on a large number of factors, including the porosity, permeability and heterogeneity of the formation, the technique used and the location of injection wells. 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 14 16 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: - the timing and amount of capital expenditures; - the operator's expertise and financial resources; - the approval of other participants in drilling wells; and - 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 10% of our total SEC PV-10 value as of June 30, 2000, is currently subject to a lawsuit that may create uncertainty as to the title 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 which 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 our royalty interest in the J.C. Martin field to the plaintiff retroactive to the date we acquired the 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 approximately 14% of our SEC PV-10 as of June 30, 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 prospectus 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 prospectus are based on the assumption that future oil and natural gas prices remain the same as oil and natural gas prices at June 30, 2000. The NYMEX prices as of June 30, 2000, used for purposes of our estimates were $32.50 per Bbl of 15 17 oil and $4.33 per MMbtu of 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 WRITEDOWNS 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: - downward adjustments to our estimated proved reserves; - increases in our estimates of development costs; or - 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. 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 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. 16 18 RISKS RELATING TO THE OFFERING AND 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 November 11, 1999, Nasdaq delisted our common stock from trading on the Nasdaq SmallCap Market because of our failure to meet the minimum net tangible asset base, the minimum market capitalization and the minimum trading price thresholds. This has resulted in our common stock being quoted on the OTC Bulletin Board. Many institutional and other investors refuse to invest in stocks that are traded at levels below the Nasdaq SmallCap Market which could make our efforts to raise capital more difficult. In addition, the firms that currently make a market for our common stock could discontinue that role. OTC Bulletin Board stocks are often lightly traded or not traded at all on any given day. Our inability to maintain the listing of the common stock on the Nasdaq National Market or any other stock exchange will negatively affect the liquidity and marketability of the common stock. 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 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. 17 19 FORWARD-LOOKING STATEMENTS We have made forward-looking statements in this prospectus 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: - our oil and natural gas reserves; - future acquisitions; - future drilling and operations; - future capital expenditures; - future production of oil and natural gas; and - future net cash flow. You should understand that the following important factors, in addition to those discussed elsewhere in this prospectus, 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: - the timing and extent of changes in prices for oil and natural gas; - the need to acquire, develop and replace reserves; - our ability to obtain financing to fund our business strategy; - environmental risks; - drilling and operating risks; - risks related to exploration, development and exploitation projects; - competition; - government regulation; and - 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 "Risk Factors" beginning on page 10. 18 20 THE RECAPITALIZATION INTRODUCTION Simultaneously with the closing of this offering, we will complete the recapitalization which includes the following: - a reverse stock split of every 156 outstanding shares of our common stock into one share; - the exchange of 9,600,000 outstanding shares of our Series A preferred stock for 212,500 shares of post reverse-split common stock; - the exchange of 2,173 outstanding shares of our Series C preferred stock and warrants exercisable for 340,153 shares of common stock for 120,000 shares of post reverse-split common stock; - the exchange of the 1,593,918 remaining unexercised common stock repricing rights and warrants exercisable for 655,000 shares of common stock for 400,000 shares of post reverse-split common stock; and - the repurchase of $75 million face value of our senior notes for approximately $52.5 million. At our stockholders meeting on September 18, 2000, our stockholders approved the first four elements of the recapitalization. The repurchase of our senior notes does not require stockholder approval. Our board of directors believes that the recapitalization will have the following positive effects: - the recapitalization will significantly improve our chances to access the equity capital markets and pursue our growth strategy; - our stockholders' equity will increase after the recapitalization because the amount of our indebtedness will be reduced at a discount; - the termination of the dilutive share issuance rights, coupled with the reverse stock split, will lessen the depressive effects on the market price of the common stock; - there will no longer be any outstanding shares of preferred stock having dividend or liquidation preferences over common stock; and - no stockholder will have rights to require us to repurchase their stock. Upon completion of the recapitalization and this offering, there will be outstanding 11,250,000 shares of our common stock, no shares of preferred stock and no repricing rights. The closing of this offering is a condition to the completion of the recapitalization, and the completion of the recapitalization is a condition to the completion of this offering. BACKGROUND DILUTIVE EFFECT OF CONVERTIBLE SECURITIES. One of the purposes of the recapitalization is to eliminate the overhang on our common stock resulting from the dilutive effects of our outstanding shares of Series A preferred stock, Series C preferred stock and common stock repricing rights. We issued 9,600,000 shares of Series A preferred stock in March 1997 for total gross proceeds of $5 million. We issued 10,400 shares of Series C preferred stock in December 1997 for total gross proceeds of $10.4 million. We issued 3,428,574 shares of common stock with repricing rights attached in July 1998 for total gross proceeds of $24 million and we issued an additional 416,667 shares of common stock with repricing rights attached in November 1998 for total gross proceeds of $2.5 million. While each share of Series A preferred stock is convertible into one share of pre-split common stock, the number of shares of common stock issuable upon conversion of the Series C preferred stock and upon the exercise of repricing rights increases as the bid price of our common stock decreases. If the relevant common stock bid price is $2.00, a share of Series C preferred stock would be convertible into 500 shares 19 21 of common stock, a July 1998 repricing right would be convertible into 3.48 shares of common stock and a November 1998 repricing right would be convertible into 2.84 shares of common stock. If the relevant bid price is $0.20, a share of Series C preferred stock would be convertible into 5,000 shares of common stock, a July 1998 repricing right would be convertible into 43.8 shares of common stock and a November 1998 repricing right would be convertible into 37.4 shares of common stock. As of October 4, 2000, there were 9,600,000 shares of Series A preferred stock, 2,173 shares of Series C preferred stock and 1,593,918 repricing rights outstanding. At that time the relevant bid price of our common stock for the purposes of conversion of Series C preferred stock or exercise of repricing rights was $0.049 per share. At that price, we would have been obligated to issue 342,591,531 shares of common stock if all outstanding shares of preferred stock and repricing rights had been converted into shares of common stock. ISSUANCE OF SENIOR NOTES. In July 1998 we issued $125 million of 12 1/2% senior notes due 2008. We used the net proceeds of the sale of these notes to retire a portion of the Bank of Montreal/Enron bridge facility that we put in place to complete the purchase of the Morgan Properties. We originally issued these senior notes in a Rule 144A private placement. These notes have traded at increasing discounts to face value since they were issued. THE RECAPITALIZATION REVERSE STOCK SPLIT. Simultaneously with the completion of this offering, we will effect a reverse stock split of every 156 outstanding shares of our common stock into one share. The shares being issued in this offering are post-reverse stock split shares. RECAPITALIZATION AGREEMENT. Under the terms of a recapitalization agreement, the holders of our Series A preferred stock, our Series C preferred stock and all unexercised common stock repricing rights will exchange their respective holdings for the following numbers of post-split common stock:
NUMBER OF SHARES OF CLASS OF HOLDERS POST-SPLIT COMMON STOCK TO BE ISSUED ---------------- ------------------------------------ Series A preferred stock.............. 212,500 Series C preferred stock.............. 120,000 Repricing rights...................... 400,000
These shares of post-reverse stock split common stock will be divided pro rata among the holders of the Series C preferred stock and the common stock repricing rights, as the case may be. Each holder has also agreed, pending completion of the recapitalization, not to submit any additional demands for the conversion of their holdings into shares of common stock nor take any other action to pursue any other rights or remedies to which they may be entitled. All securities purchase agreements, registration rights agreements, warrants and other ancillary agreements between the company and the various holders will be terminated upon completion of the recapitalization. The closing under the recapitalization agreement is subject to the following: - stockholder approval of the recapitalization and the reverse stock split, which was obtained at our stockholders meeting on September 18, 2000; - our delivery of 732,500 shares of common stock without any restrictive legend or stop transfer orders, except as otherwise provided in the recapitalization agreement; - the completion of an equity financing on or before October 31, 2000 generating net proceeds to us of at least $50 million, which condition will be satisfied by the completion of this offering; 20 22 - the repurchase of not less than $75 million in original principal amount of our 12 1/2% senior notes on or before October 31, 2000, which condition will be satisfied upon the application of the net proceeds of this offering; and - the representations and warranties contained in the recapitalization agreement being true as of the date of the agreement and the date of delivery of shares of common stock to the Series A preferred stock, the Series C preferred stock and the repricing rights holders. From and after the closing under the recapitalization agreement, the holders of Series A preferred stock, Series C preferred stock and the repricing rights agreed to release us from any claims that existed before the closing, other than claims arising out of the recapitalization agreement. REPURCHASE OF OUR SENIOR NOTES. On September 1, 2000, we commenced a tender offer to purchase for cash, on a pro rata basis among tendering holders, $75 million principal amount of our 12 1/2% senior notes under the terms and subject to the conditions set forth in the offer to purchase and consent solicitation statement. As part of the tender offer, we also solicited the consent of the holders of notes to two proposed amendments to the indenture. One of the proposed amendments would amend the restrictive covenant limiting our incurrence of debt to provide for a dollar for dollar increase in the permitted indebtedness up to a maximum of $60 million, to the extent that the equity raised pursuant to this offering exceeds $50 million, net of all costs related to issuance. The other proposed amendment would provide that a "Change of Control" will not be deemed to occur as a result of the recapitalization or this offering. This amendment will permit us to complete the recapitalization and this offering without triggering the right of each holder, at the holder's option, to require us to repurchase all or any part of the holder's notes at a cash price equal to 101% of the principal amount thereof, plus accrued and unpaid interest and liquidated damages, if any, to the payment date. We commenced the tender offer pursuant to a participation agreement, dated as of July 17, 2000, that we had entered into with the holders of approximately $94 million principal amount of the senior notes. Under the participation agreement, the holders that entered into the agreement agreed to tender their notes to us for a price of $650 per $1,000 principal amount of notes and to consent to the proposed amendments to the indenture governing the senior notes. One of the conditions to these holders' agreement to tender was that the holders of at least $110 million principal amount of notes tender their notes pursuant to the offer. As of October 4, 2000, the holders of approximately $104.3 million principal amount of notes had validly tendered and not withdrawn their notes and had consented to the proposed amendments on or before the consent date. Under the terms of the offer, these holders may not withdraw their notes after the consent date, which occurred on September 18, 2000. We have amended the participation agreement with the holders of approximately $94 million principal amount of notes to (1) increase the tender offer consideration per $1,000 principal amount of notes tendered and accepted for payment to $680 and (2) to decrease the minimum tender condition to provide that one of the conditions to the tender offer is that the holders of approximately $104 million principal amount of notes tender pursuant to the offer. As a result, on October 6, 2000, we amended the terms of the offer to increase the price and decrease the minimum tender condition, and we extended the expiration date to 5:00 p.m., New York City time on October 20, 2000. Under the terms of the offer, as amended, holders who validly tendered their notes before the consent date will receive total consideration of $700, which includes $680 for the tender of the notes and $20 for the holder's consent to the proposed amendments to the indenture, and these holders may not withdraw their notes after the consent date, which occurred on September 18, 2000. Holders who validly tender their notes after the consent date and before 5:00 p.m., New York City time on October 20, 2000, the expiration date, will receive $680 for each $1,000 principal amount of notes validly tendered and accepted for payment. 21 23 The consummation of the tender offer is subject to the satisfaction or waiver of the following conditions: - We must complete an equity offering that will yield net proceeds to us of at least $50 million on terms acceptable to us substantially concurrent with the completion of the tender offer, which condition will be satisfied upon the completion of this offering. - We must have received consents from the holders of at least 66 2/3% of the principal amount of notes with respect to the proposed amendments to the indenture. As of October 6, 2000, the holders of approximately 88% of the notes had consented to the proposed amendments. - The general conditions described in the offer statement, including that there has not been any general suspension of trading in, or limitation on prices for trading in, securities in the United States securities or financial markets and that no order or law exists that might prohibit the completion of the offer and some other matters, must be met. The effect of a repurchase of the notes pursuant to the offer and the repayment of debt under our credit agreement would be to reduce our annual interest costs from $18 million to less than $8 million. In addition, EBITDA to interest coverage would increase to approximately 3.7 to 1. As a result, we will have additional borrowing capacity under the indenture governing the senior notes and our credit agreement with Ableco Finance LLC with which to carry out our redevelopment program and finance future acquisitions. PRICE RANGE OF COMMON STOCK; DIVIDEND HISTORY Our common stock currently is quoted on the OTC Bulletin Board under the symbol "QSRI." On October 4, 2000, the last price at which our common stock was quoted on the OTC Bulletin Board was $0.049. Our common stock was quoted on the Nasdaq SmallCap Market under the symbol "QSRI" from May 1997 to November 11, 1999. On November 11, 1999, Nasdaq delisted our common stock for failing to meet the net tangible asset test, the minimum market capitalization requirement and the minimum bid price requirements. The following table sets forth the high and low closing bid prices for our common stock as reported on Nasdaq and quoted on the OTC Bulletin Board for the periods stated above. The market prices reported below have been adjusted to give retroactive effect to the 156 to 1 reverse stock split.
AS ADJUSTED FOR HISTORICAL REVERSE STOCK SPLIT --------------- ----------------------- HIGH LOW HIGH LOW ------ ------ ---------- ---------- FISCAL YEAR ENDED JUNE 30, 1999 First Quarter....................................... $8.000 $6.500 $1,248.000 $1,014.000 Second Quarter...................................... 7.000 3.375 1,092.000 526.500 Third Quarter....................................... 4.125 1.125 643.500 175.500 Fourth Quarter...................................... 1.469 0.937 229.164 146.172 FISCAL YEAR ENDING JUNE 30, 2000 First Quarter....................................... $0.938 $0.281 $ 146.328 $ 43.836 Second Quarter...................................... 0.594 0.281 92.664 43.836 Third Quarter....................................... 0.530 0.281 82.680 43.836 Fourth Quarter...................................... 0.406 0.094 63.336 14.664 FISCAL YEAR ENDING JUNE 30, 2001 First Quarter....................................... $0.266 $0.047 $ 41.496 $ 7.316 Second Quarter (through October 4, 2000)............ $0.049 $0.045 $ 7.644 $ 7.020
As of October 3, 2000, we had approximately 938 record holders of our shares of common stock. We have filed an application to designate our common stock on the Nasdaq National Market subject to issuance. However, we cannot assure you that we will be able to designate or list our common stock on the Nasdaq National Market or any other market or exchange, or, if we are able to designate or list our common stock, that we will be able to continue that designation or listing. 22 24 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 other factors our board of directors believes relevant. USE OF PROCEEDS We estimate that we will receive net proceeds of approximately $74 million, or $84.5 million if the underwriters exercise their over-allotment option in full, from the sale of the shares of common stock offered by this prospectus, after deducting underwriting discounts and commissions and estimated offering expenses. This estimate assumes a public offering price of $8.00 per share. We intend to use the net proceeds as follows: - approximately $52.5 million to purchase up to $75 million in aggregate original principal amount of our 12 1/2% senior notes at a discount; - to repay debt outstanding under our credit agreement, which as of September 30, 2000 was approximately $14 million; and - any remainder to fund future acquisitions of oil and natural gas properties consistent with our business strategy and to fund other general corporate working capital requirements including drilling and workover projects and other exploitation and development activities. We believe that the availability of the remaining net proceeds will enhance our ability to compete for and complete additional acquisitions, but we cannot assure you that even if proceeds are available for acquisitions that we will be able to buy properties at attractive prices. As of the date of this prospectus, we do not have any agreements or understanding regarding acquisitions.
AMOUNTS -------------- (IN THOUSANDS) SOURCES Common stock.......................................... $80,000(1) Less discount and offering expenses................... $ 6,000 ------- Net proceeds..................................... $74,000 ======= USES Repurchase of 12 1/2% senior notes(2)................. $52,500 Repayment of debt under our credit agreement(3)....... 14,000 Working capital....................................... 7,500 ------- Total....................................... $74,000 =======
--------------- (1) If the underwriters' over-allotment is exercised in full, the gross proceeds will be $92 million. (2) We borrowed the $125 million aggregate original principal amount under our 12 1/2% senior notes to acquire net profits interests and overriding royalty interests in oil and natural gas properties. The interest rate on our senior notes is 12 1/2% per annum, and the maturity date is July 1, 2008. (3) As of June 30, 2000, we had $18.5 million debt outstanding under our credit agreement. The interest rate under our credit agreement is currently 11.5% per annum, and the maturity date is October 22, 2001. 23 25 CAPITALIZATION The following table presents our capitalization as of June 30, 2000 on an actual basis and on a pro forma basis giving effect to the recapitalization and this offering, assuming that it yields net proceeds to us of $74 million. You should read this table in conjunction with our consolidated financial statements and our unaudited pro forma condensed consolidated financial statements included in this prospectus.
AT JUNE 30, 2000 ---------------------- HISTORICAL PRO FORMA ---------- --------- (IN THOUSANDS) Total long-term indebtedness (including current portion): Credit Agreement.......................................... $ 18,500 $ -- 12 1/2% Senior Notes due 2008............................. 125,000 50,000 Other..................................................... 584 584 -------- -------- Total long-term indebtedness...................... 144,084 50,584 Stockholders' equity: Preferred Stock: Series A Participating Convertible Preferred Stock, $0.01 par value; 9,600,000 shares authorized; 9,600,000 shares issued and outstanding............... 96 -- Series B Participating Convertible Preferred Stock, $0.01 par value; 9,600,000 shares authorized; no shares issued or outstanding.......................... -- -- Series C Convertible Preferred Stock, $0.01 par value; 10,400 shares authorized; 2,173 shares issued and outstanding........................................... -- -- Common Stock.............................................. 135 2,633 Additional paid-in capital................................ 65,112 129,459 Accumulated deficit....................................... (92,934) (69,208) Treasury stock, at cost................................... (7,251) -- -------- -------- Total stockholders' equity (net capital deficiency)...................................... (34,842) 62,884 -------- -------- Total capitalization.............................. $109,242 $113,468 ======== ========
24 26 DILUTION Our pro forma net tangible book value per share of common stock as of June 30, 2000 was zero due to a stockholders' deficit of approximately $34.8 million. Pro forma net tangible book value per share before this offering represents the amount of our total tangible assets reduced by the amount of our total liabilities and divided by the total number of shares of common stock outstanding assuming that the reverse stock split and the exchange of shares by the Series A preferred stockholder, the Series C preferred stockholders and the repricing rights holders have been completed. After giving effect to the entire recapitalization and the sale of 10,000,000 shares of common stock offered by us at an assumed initial public offering price of $8.00 per share, and after deducting the underwriting discount and estimated offering expenses payable by us, our pro forma net tangible book value at June 30, 2000 would have been approximately $58.2 million or $5.17 per share of common stock. This represents an immediate increase in pro forma net tangible book value of $5.17 per share to existing stockholders and an immediate dilution of $2.83 per share to new investors purchasing common stock in this offering. Dilution in pro forma net tangible book value per share represents the difference between the amount per share paid by purchasers of common stock in this offering and the pro forma net tangible book value per share of common stock immediately after the completion of this offering and the recapitalization. The following table illustrates this dilution: Assuming public offering price per share............... $ 8.00 Pro forma net tangible book value per share as of June 30, 2000 before the offering......................... $ -- Increase per share attributable to new investors....... $ 5.17 Pro forma net tangible book value per share after the offering and the recapitalization.................... $ 5.17 Pro forma net tangible book value after the offering and the recapitalization............................. $58,202,000 Dilution per share to new investors.................... $ 2.83
The following table summarizes on a pro forma basis, after giving effect to this offering, as of June 30, 2000, the differences between the existing stockholders and the new investors with respect to the number of shares of common stock purchased from us, the total consideration paid to us and the average price per share paid based upon an assumed initial public offering price of $8.00 per share and before deducting the underwriting discounts and commissions and our estimated offering expenses:
SHARES PURCHASED TOTAL CONSIDERATION -------------------- ---------------------- NUMBER PERCENT AMOUNT PERCENT ---------- ------- ------------ ------- Existing stockholders......................... 1,250,000 11% $ 58,092,000 42% New investors................................. 10,000,000 89% $ 80,000,000 58% ---------- --- ------------ --- Total:.............................. 11,250,000 100% $138,092,000 100%
The preceding tables assume no exercise of the underwriters' over-allotment option. To the extent the over-allotment option is exercised, there will be further dilution to new investors. See note 5 of our notes to consolidated financial statements included in this prospectus. 25 27 SELECTED CONSOLIDATED FINANCIAL DATA The following table sets forth our selected consolidated financial data for each of the periods indicated. The financial data for the five years ended June 30, 2000 are derived from our audited consolidated financial statements. You should read this information along with our consolidated financial statements and the notes to those financial statements included in this prospectus. For further discussion of our consolidated financial statements, see "Management's Discussion and Analysis of Financial Condition and Results and Operations."
YEAR ENDED JUNE 30, ------------------------------------------------- 1996 1997 1998 1999 2000 ------- ------- -------- -------- ------- (IN THOUSANDS, EXCEPT PER SHARE DATA) OPERATIONS DATA: Oil and natural gas sales(1)............... $ 2,079 $ 4,381 $ 12,665 $ 33,783 $32,584 Oil and natural gas production expenses(1).............................. 1,175 2,507 6,333 9,127 7,097 ------- ------- -------- -------- ------- Net oil and natural gas revenues........... 904 1,874 6,332 24,656 25,487 General and administrative expenses........ 1,113 1,452 2,259 3,534 3,026 ------- ------- -------- -------- ------- EBITDA(2).................................. (209) 422 4,073 21,122 22,461 Interest and financing costs(3)............ 421 878 3,957 17,003 16,945 Depreciation, depletion, and amortization(4).......................... 630 982 4,809 13,354 10,259 Hedge contract termination costs(5)........ -- -- -- -- 3,328 Ceiling test write-down(6)................. -- -- 28,166 35,033 -- Interest and other income.................. (71) (300) (105) (326) (143) Extraordinary item(7)...................... -- 171 -- 3,549 1,130 ------- ------- -------- -------- ------- Net loss................................... $(1,189) $(1,309) $(32,754) $(47,491) $(9,058) ======= ======= ======== ======== ======= Net loss per common share.................. $ (0.05) $ (0.05) $ (1.44) $ (1.51) $ (0.21) CASH FLOWS DATA: Net cash provided by (used in) operating activities............................... $ (620) $ 263 $ 1,041 $ 9,504 $ (834) Net cash used in investing activities...... (5,502) (4,305) (154,342) (1,611) (3,874) Net cash provided by financing activities............................... 6,622 3,752 154,021 444 7,222 Net increase (decrease) in cash............ 500 (290) 720 8,337 2,514
AT JUNE 30, -------------------------------------------------- 1996 1997 1998 1999 2000 ------- ------- -------- -------- -------- (IN THOUSANDS) BALANCE SHEET DATA (AT END OF PERIOD): Total current assets...................... $ 1,533 $ 1,066 $ 6,411 $ 14,019 $ 18,524 Property and equipment, net............... 9,662 16,187 142,467 97,198 92,525 Deferred assets........................... 88 -- 4,797 7,993 8,144 Total assets.............................. 11,283 17,253 153,675 119,210 119,193 Total current liabilities................. 1,450 3,670 6,836 11,142 10,535 Long-term obligations, net of current portion................................. 6,670 7,152 153,619 133,852 143,500 Total stockholders' equity (deficit)...... 3,163 6,431 (6,780) (25,784) (34,842)
--------------- (1) Oil and natural gas sales and production expenses related to net profits interests have been presented as if the net profits interests were working interests. Oil and natural gas sales include revenues relating to the net profits interests of $6,219,000 for the year ended June 30, 1998, $29,071,000 for the year ended June 30, 1999, and $28,715,000 for the year ended June 30, 2000. Oil and natural gas production expenses include expenses relating to the net profits interests of $1,787,000 for the year ended June 30, 1998, $5,931,000 for the year ended June 30, 1999, and $5,725,000 for the year ended June 30, 2000. 26 28 (2) EBITDA represents earnings before interest expense, income taxes, depreciation, depletion and amortization expense, 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 $22,000 of amortized deferred charges related to our natural gas price hedging program for the year ended June 30, 1998. Depreciation, depletion and amortization for the year ended June 30, 1999 includes amortized deferred charges related to debt obligations of $1.3 million, and $120,000 of amortized deferred charges related to our natural gas price hedging program. Depreciation, depletion and amortization includes for the year ended June 30, 2000 $1.6 million of amortized deferred charges related to debt obligations, and $98,000 of amortized deferred charges related to our natural gas price hedging program. (5) In conjunction with the execution of our restated credit agreement in October 1999, we terminated the ceiling portion of a natural gas hedging contract at a cost of $3,328,000. (6) In accordance with the full cost method of accounting, the results of operations for the year ended June 30, 1998 include a writedown of oil and natural gas properties of $28,166,000 and for the year ended June 30, 1999 include a writedown of $35,033,000. (7) During February 1997, we recognized a loss of $171,000 in connection with restructuring a debt obligation. During July 1998, we terminated a LIBOR interest rate swap agreement at a cost of $3,549,000. During October 1999, we retired borrowings under our old credit agreement and entered into a restated credit agreement with a new lender. As a result, we wrote off $1,130,000 of deferred costs relating to the old credit agreement. We did not pay dividends in any of the periods presented. 27 29 UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following unaudited pro forma condensed consolidated financial statements present the effects of: the recapitalization, including the reverse stock split, the receipt of $74 million of net proceeds from this offering, the acquisition of $75 million original face value of our 12 1/2% senior notes for approximately $52.5 million and the repayment of the borrowings under our credit facility. The unaudited pro forma condensed consolidated balance sheet presents the financial position of the company as of June 30, 2000 assuming the proposed transactions had occurred as of June 30, 2000. This pro forma information is based upon the historical June 30, 2000 balance sheet of the company included elsewhere in this prospectus. The unaudited pro forma condensed consolidated statements of operations give effect to the proposed transactions as if such transactions had been entered into on July 1, 1999. This pro forma information is based upon the historical results of operations of the company for the year ended June 30, 2000, included elsewhere in this prospectus. The unaudited pro forma condensed consolidated financial statements are based upon available information and assumptions that management of the company believes are reasonable. The unaudited pro forma condensed consolidated financial data do not purport to represent the financial position or results of operations which would have occurred if these transactions had been completed on the dates indicated or the company's financial position or results of operations for any future date or period. You should read this unaudited pro forma condensed consolidated financial data together with the company's historical financial statements and the notes to those financial statements included in this prospectus. 28 30 DEVX ENERGY, INC. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET JUNE 30, 2000 AMOUNTS IN THOUSANDS EXCEPT SHARE AND PER SHARE DATA
PRO FORMA HISTORICAL ADJUSTMENTS PRO FORMA ------------ ------------ ------------ ASSETS Current assets Cash............................................. $ 11,881 $ 74,000(3) $ 14,881 (52,500)(4) (18,500)(5) Other current assets............................. 6,643 6,643 ------------ ------------ ------------ Total current assets............................... 18,524 3,000 21,524 Net property & equipment........................... 92,525 92,525 Other assets....................................... 8,144 (3,462)(4) 4,682 ------------ ------------ ------------ Total assets............................. $ 119,193 $ (462) $ 118,731 ============ ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities Accounts payable and accrued liabilities......... $ 9,951 $ (4,688)(4) $ 5,263 Current portion of long-term debt................ 584 584 ------------ ------------ ------------ Total current liabilities.......................... 10,535 (4,688) 5,847 (18,500)(5) Long-term obligations, net of current portion...... 143,500 (75,000)(4) 50,000 ------------ ------------ ------------ Total liabilities........................ 154,035 (98,188) 55,847 ============ ============ ============ STOCKHOLDERS' EQUITY (DEFICIT) Preferred stock.................................. 96 (96)(1) -- Common stock..................................... 135 158(1) 2,633 2,340(3) Additional paid-in capital....................... 65,112 (62)(1) 129,459 71,660(3) (7,251)(1) (69,208) Accumulated Deficit.............................. (92,934) 23,726(4) Treasury stock................................... (7,251) 7,251(1) -- ------------ ------------ ------------ Total stockholders' equity (deficit)..... (34,842) 97,726 62,884 ------------ ------------ ------------ Total liabilities and stockholders' equity (deficit).............................. $ 119,193 $ (462) $ 118,731 ============ ============ ============ SHARE INFORMATION Shares Authorized: Preferred Stock.................................. 50,000,000 -- 50,000,000 Common Stock..................................... 100,000,000 -- 100,000,000 Shares Issued and Outstanding Preferred Stock.................................... 9,602,173 (9,602,173)(1) -- Common Stock....................................... 80,688,538 732,500(1) 11,250,000 (80,171,038)(2) 10,000,000(3)
See accompanying notes. 29 31 DEVX ENERGY, INC. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED JUNE 30, 2000 AMOUNTS IN THOUSANDS EXCEPT SHARE AND PER SHARE DATA
PRO FORMA HISTORICAL ADJUSTMENTS PRO FORMA ----------- ------------ ----------- Revenues: Oil and natural gas revenues...................... $ 3,967 $ -- $ 3,967 Net profits and royalties interests............... 22,990 22,990 Interest and other income......................... 143 143 ----------- ------------ ----------- Total revenues............................ 27,100 27,100 Expenses: Oil and natural gas production expenses........... 1,372 1,372 General and administrative expenses............... 3,026 3,026 Interest and financing costs...................... 18,561 (9,807)(6) 7,626 (1,128)(7) Hedge contract termination costs.................. 3,328 3,328 Depreciation, depletion and amortization.......... 8,741 8,741 ----------- ------------ ----------- 35,028 (10,935) 24,093 Net income (loss) before extraordinary loss......... $ (7,928) $ 10,935 $ 3,007 =========== ============ =========== Net income (loss) before extraordinary loss per common share, basic and diluted................... $ (0.18) $ 0.27 =========== ============ =========== Weighted average shares of common stock outstanding during the period................................. 43,465,423 732,500(8) 11,011,125 (43,186,798)(9) 10,000,000(10)
See accompanying notes. 30 32 DEVX ENERGY, INC. NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOTE A. GENERAL Simultaneously with the closing of this offering, we will complete a recapitalization which includes the following: - a reverse stock split of every 156 outstanding shares of our common stock into one share; - the exchange of 9,600,000 outstanding shares of our Series A preferred stock for 212,500 shares of post reverse-split common stock; - the exchange of 2,173 outstanding shares of our Series C preferred stock and warrants exercisable for 340,153 shares of common stock for 120,000 shares of post reverse-split common stock; - the exchange of the 1,593,918 remaining unexercised common stock repricing rights and warrants exercisable for 655,000 shares of common stock for 400,000 shares of post reverse-split common stock. - the repurchase of $75 million face value of our senior notes for approximately $52.5 million. At our stockholders meeting on September 18, 2000, our stockholders approved the first four elements of the recapitalization. The repurchase of our senior notes does not require stockholder approval. NOTE B. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET The accompanying unaudited pro forma condensed consolidated balance sheet assumes the transactions discussed in Note A above were entered into on June 30, 2000 and reflects the following pro forma adjustments: (1) To record the effects of the following recapitalization transactions: - the exchange of the 9,600,000 outstanding shares of Series A preferred stock for 212,500 shares of post reverse-split common stock; - the exchange of the 2,173 outstanding shares of Series C preferred stock and warrants exercisable for 340,153 shares of common stock for 120,000 shares of post reverse-split common stock; - the exchange of the 1,593,918 remaining unexercised common stock repricing rights and warrants exercisable for 655,000 shares of common stock for 400,000 shares of post reverse-split common stock; and - the cancellation of existing treasury stock. (2) To record a proposed reverse stock split of our common stock whereby every 156 outstanding shares of common stock will be reverse split into one share outstanding. (3) To record the net proceeds from this offering of approximately $74 million in cash and the issuance of 10,000,000 shares of post-reverse split common stock. (4) To record the retirement at a discount of $75 million original face value of our outstanding senior notes for approximately $52.5 million, including the writeoff of unamortized debt issuance costs and accrued interest payable. (5) To record repayment of the borrowings under our credit facility. 31 33 NOTE C. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS The accompanying unaudited pro forma condensed consolidated statements of operations assume the transactions discussed in Note A above were entered into on July 1, 1999 and reflect the following pro forma adjustments: (6) To record a reduction in interest expense related to the retirement of $75 million original face value of our outstanding senior notes. (7) To record a reduction in interest expense related to the repayment of the borrowings under our credit facility. (8) To record the effects of the number of post reverse stock split common shares issued to holders of Series A and C preferred stock and stock repricing rights and warrants in the recapitalization. (9) To record the effects of the proposed reverse stock split on the number of weighted average shares outstanding during the period presented. (10) To record the shares of common stock issued in conjunction with this offering by approximately $74 million. 32 34 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. Our strategy to achieve these goals consists of these elements: - develop, exploit and explore our existing oil and natural gas properties; - identify acquisition opportunities that complement our existing properties; and - 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 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 $0.7 million in the fiscal year ended June 30, 1998, $0.9 million in the fiscal year ended June 30, 1999 and $0.7 million in the fiscal year ended June 30, 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 discussion and analysis reflects the operating results as if the net profits interests were working interests. We believe that this will provide the readers of the report with a more meaningful understanding of the underlying operating results and conditions for the period. THE YEAR ENDED JUNE 30, 2000 COMPARED TO THE YEAR ENDED JUNE 30, 1999 REVENUES. Total revenues during the year ended June 30, 2000 were $32.6 million, a decrease of $1.2 million from $33.8 million for the year ended June 30, 1999. Our revenues were derived from the sale of 10.6 Bcf of natural gas at an average price per Mcf of $2.59 and 224,000 barrels of oil at an average price per barrel of $22.76. During the year ended June 30, 1999 our revenues were derived from the sale of 13.0 Bcf of natural gas, at an average price per Mcf of $2.13, and 500,000 barrels of oil, at an average price per barrel of $12.37. Overall we produced 12.0 Bcfe at an average price of $2.72 per Mcfe during the year ended June 30, 2000 as compared to 16.0 Bcfe at an average price of $2.12 per Mcfe during the year ended June 30, 1999. This represents a decrease of 4.0 Bcfe (25%) in production and an increase of $0.60 (28%) in the average price we received. We produced 224,000 barrels of oil during the year ended June 30, 2000, a decrease of 276,000 barrels (55%) from the 500,000 barrels produced during the comparable period in 1999. The properties that we sold at the end of June 1999 represent 196,000 barrels (71%) of the total decrease of 276,000 barrels. Production from the properties that we owned during both periods decreased by 80,000 barrels. This represents a 26% decline from volumes produced during the year ended June 30, 1999. 33 35 The decrease in production of oil from the properties owned during the comparative periods is comprised of three components: - The Segno field has not been meeting production expectations. This under performance represents approximately 37% of the decrease in production from the properties that we owned during both periods. Remedial action is being taken to rehabilitate this field. - 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, we returned to production those wells that produce economically. In addition, we are in the early stages of a redevelopment program in the Caprock Field to enhance production. We have drilled four single lateral injection wells and one dual-lateral producing well. These five wells along with the production facilities and a water injection plant constitute phase one of the redevelopment program. Phase one covers 640 acres out of the approximate 20,000 acres we control in the Caprock Field. - The final component of the production decline is the result of the natural depletion of our oil reservoirs. We produced 10.6 Bcf of natural gas during the year ended June 30, 2000, down from the 13.0 Bcf produced during the comparable period in 1999. The properties that we sold at the end of June 1999 represent 1.0 Bcf (43%) of the total decrease of 2.3 Bcf. Production from the properties that we owned during both periods decreased by 1.3 Bcf. This represents an 11% decline from the volumes produced during the year ended June 30, 1999. The decrease in production from the properties owned during the comparative periods is comprised of three components: - The Gilmer field has experienced production declines in excess of what was expected. The operator of the property has commenced drilling and completion efforts on the first two of a series of proposed infield wells to increase production. - Our successful development and exploitation program in south Texas resumed in August 1999 and ten new wells have been drilled through the end of June 2000. These wells have high initial production rates and significant initial decline rates, with approximately half of total reserves being produced during the first year. - The final component of the production decline is the result of the natural depletion of our natural gas reservoirs. On a Bcfe basis, production for the year ended June 30, 2000 was 12 Bcfe, down 4.0 Bcfe (25%) from the 16.0 Bcfe produced during the comparable period in 1999. The properties that we sold at the end of June 1999 represent 2.2 Bcfe of the total decrease of 4.0 Bcfe. Production from the properties that we owned during both periods decreased by 1.8 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 June 30, 2000 was $22.76, an increase of $10.39 per barrel (84%) over the $12.37 per barrel during the year ended June 30, 2000. The average price per Mcf of natural gas sold by us was $2.59 during the year ended June 30, 2000, an increase of $0.46 per Mcf (22%) over the $2.13 per Mcf during the comparable period in 1999. Oil prices have remained at these elevated levels subsequent to June 30, 2000. Natural gas prices were volatile throughout the year, and have remained so subsequent to June 30, 2000. On an Mcfe basis, the average price received by us during the year ended June 30, 2000 was $2.72, a $0.60 increase (28%) over the $2.12 we received during the comparable period in 1999. During the year ended June 30, 2000 we paid $470,000 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 $2.10 per barrel (8%). During the year ended June 30, 2000 we paid $981,000 in cash settlements and amortized $98,000 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 $0.10 (4%). Payments 34 36 made as a result of our oil price-hedging program during the year ended June 30, 1999 were insignificant. During the comparable period in 1999 we received $1.7 million 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 $0.13 per Mcf (6%). COSTS AND EXPENSES. Operating costs and expenses for the year ended June 30, 2000, 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 $37.4 million. Of this total, lease operating expenses and production taxes were $7.1 million, general and administrative expenses were $3.0 million, interest charges were $18.6 million and depletion, depreciation and amortization costs were $8.7 million. Operating costs and expenses for the year ended June 30, 1999, exclusive of a non-cash ceiling test write-down of $35.0 million and an extraordinary charge of $3.5 million, were $43.0 million. Of this total, lease operating expenses and production taxes were $9.1 million, general and administrative expenses were $3.5 million, interest charges were $18.4 million and depletion, depreciation and amortization costs were $11.9 million. Severance and production taxes, which are based on the revenues derived from the sale of oil and natural gas, were $1.43 million during the year ended June 30, 2000, as compared to $1.38 million during the comparable period in 1999, an increase of $55,000, or 4%. While revenues, after adjusting for commodity hedging contract settlements, decreased 3% during the comparable periods wellhead revenues increased by 6%. Severance taxes are applied only to wellhead revenues. Our commodity hedge results were the primary cause for our severance and production taxes increasing, on a percentage basis, while overall revenues decreased. On a cost per Mcfe basis, severance taxes were $0.12 per Mcfe for the year ended June 30, 2000 compared to $0.09 per Mcfe for the comparable period ending June 30, 1999, an increase of 39%. Average wellhead prices rose by 41%, from $2.02 per Mcfe during the year ended June 30, 1999 to $2.85 per Mcfe during the year ended June 30, 2000. Our lease operating expenses fell to $5.7 million for the year ended June 30, 2000, a decrease of $2.1 million, or 27%, from the $7.8 million incurred during the comparable period in 1999. This decrease is primarily the result of reduced costs from comparable properties and the elimination of costs from the properties we sold at the end of June 1999. Lease operating expenses were $0.47 per Mcfe during the year ended June 30, 2000, a decrease of $0.02, or 3%, from the $0.49 per Mcfe incurred during the comparable period in 1999. This improvement is primarily the result of the sale of properties at the end of June 1999, which had higher operating costs per Mcfe than the properties we currently own. General and administrative expenses were $3.0 million during the year ended June 30, 2000 compared to $3.5 million incurred during the year ended June 30, 1999. This decrease of $508,000 (14%) consists primarily of reduction in personnel costs and professional fees. On a per unit basis, general and administrative expenses for the year ended June 30, 2000 were $0.25 per Mcfe, an increase of $0.03 per Mcfe (14%) from the $0.22 per Mcfe incurred during the year ended June 30, 1999. This per unit increase in general and administrative expenses is a result of our decreased level of oil and natural gas production. Interest expense for the year ended June 30, 2000 was $18.6 million. This was comprised of $17.0 million paid or payable in cash and $1.6 million of amortized deferred costs incurred at the time that the related debt obligations were incurred. During the year ended June 30, 1999 our interest expense was $18.3 million. This was comprised of $17.0 million paid or payable in cash and $1.3 million of amortized deferred debt issuance costs incurred at the time that the related debt obligations were established. The increase of $0.3 million in amortization of deferred debt issuance costs arose as a result of replacing our old credit agreement with our new credit agreement. We recorded an extraordinary loss of $1.1 million, in connection with the replacement of our old credit agreement, which loss represented the unamortized deferred costs incurred with respect to the old credit agreement. 35 37 On a per unit basis, cash interest expense for the year ended June 30, 2000 was $1.42 per Mcfe, as compared to $1.06 per Mcfe during the year ended June 30, 1999. This is the result of the 25% reduction in production we had during the year ended June 30, 2000, as compared to the year ended June 30, 1999. The decrease in depletion, depreciation and amortization costs of $3.1 million was a result of the 25% decrease in the volume of oil and natural gas produced by us during the year ended June 30, 2000 as compared to the year ended June 30, 1999. On a cost per Mcfe basis, the depletion, depreciation and amortization costs decreased by $0.03 per Mcfe (3%). This decrease is a function of: - the $35 million non-cash write-down we recorded at December 31, 1998; and - the reduced future capital expenditures required to develop the proved reserves. 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 have incurred losses since inception, including $9.1 million, or $0.21 per common share, for the year ended June 30, 2000 compared to $47.5 million, or $1.51 per common share for the year ended June 30, 1999. 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 $35 million and $28 million during the years ended June 30, 1999 and 1998, respectively. Future declines in oil and natural gas prices could lead to additional non-cash write-downs of our oil and natural gas properties. THE YEAR ENDED JUNE 30, 1999 COMPARED TO THE YEAR ENDED JUNE 30, 1998 REVENUES. Total revenues during the year ended June 30, 1999 were $33.8 million, an increase of $21.1 million over the $12.7 million for the year ended June 30, 1998. Our revenues were derived from the sale of 13.0 Bcf of natural gas at an average price per Mcf of $2.13 and 500,000 barrels of oil at an average price per barrel of $12.37. During the year ended June 30, 1998 our revenues were derived from the sale of 3.4 Bcf of natural gas, at an average price per Mcf of $2.27, and 325,000 barrels of oil, at an average price per barrel of $15.52. The two periods are not readily comparable because of our significant growth during the year ended June 30, 1998, primarily resulting from the April 1998 acquisition of the Morgan Properties. Production from properties owned throughout both periods was 1.0 Bcf of natural gas and 223,000 barrels of oil during the year ended June 30, 1999. This represents an increase of 0.1 Bcf, or 14%, over the 0.9 Bcf of natural gas, and a decrease of 26,000 barrels, or 11%, from the 250,000 barrels of oil produced during the year ended June 30, 1998. The increase in natural gas production is a reflection of our successful exploitation and development programs implemented during the year ended June 30, 1999, offset by the natural rate of depletion of the reservoirs associated with these properties. The decrease in oil production is a combination of the decision to temporarily reduce production from some producing areas with relatively high production costs, due to the low price of oil received during the year combined with the natural rate of depletion of the reservoirs associated with these properties. The production of oil from those properties temporarily shut in during the period of low oil prices was restored following the return of oil prices to their currently higher levels. Production from properties acquired during 1998 was 11.9 Bcf of natural gas and 276,000 barrels of oil during 1999 as compared to 2.4 Bcf of natural gas and 75,000 barrels of oil during 1998. COSTS AND EXPENSES. Operating costs and expenses for the year ended June 30, 1999, exclusive of a non-cash ceiling test write-down of $35.0 million and an extraordinary charge of $3.5 million, were $43.0 million. Of this total, lease operating expenses and production taxes were $9.1 million, general and administrative expenses were $3.5 million, interest charges were $18.3 million and depletion, depreciation and amortization costs were $11.9 million. Operating costs and expenses for the year ended June 30, 1998, exclusive of a non-cash ceiling test write-down of $28.2 million, were $17.4 million. Of this total, lease 36 38 operating expenses and production taxes were $6.3 million, general and administrative costs were $2.3 million, interest charges were $4.0 million, and depletion, depreciation and amortization costs were $4.8 million. The increase in lease operating expenses and production taxes is a result of our increased levels of oil and natural gas production. When lease operating expenses and production taxes are compared on a cost per unit basis, the cost of producing an Mcfe during the year ended June 30, 1999 decreased by $0.62 per Mcfe, or 52%, to $0.58 from the $1.19 per Mcfe achieved during the year ended June 30, 1998. This decrease in production costs per unit is primarily the result of acquiring properties in April 1998 with lower operating costs per unit than our other properties. General and administrative expenses have increased by $1.3 million as a result of our increased size requiring additional employees and incremental costs; however, on a per unit basis, general and administrative expenses for the year ended June 30, 1999 were $0.22 per Mcfe, a decrease of $0.21 per Mcfe, or 49%, from the $0.43 per Mcfe incurred during the year ended June 30, 1998. This per unit decline in general and administrative expenses is a result of our increased level of oil and natural gas production. Interest expense for the year ended June 30, 1999 was $18.3 million. This is comprised of $17.0 million paid or payable in cash and $1.3 million of amortized deferred costs incurred at the time that the related debt obligations were incurred. During the year ended June 30, 1998 total interest expense was $4.0 million, which was comprised of $3.9 million paid or payable in cash and $0.1 million of amortized deferred costs incurred at the time that the related debt obligations were incurred. The increase of $14.3 million in interest expense is due to an increase in the average interest bearing debt outstanding. During the year ended June 30, 1999 we had average interest bearing debt outstanding of $139.3 million, as compared to $48.5 million during the year ended June 30, 1998. On a per unit basis, cash interest expense for the year ended June 30, 1999 was $1.06 per Mcfe, as compared to $0.75 per Mcfe during the year ended June 30, 1998. The increase in depletion, depreciation and amortization costs of $7.1 million is a result of the increased volume of oil and natural gas produced by us and the higher per unit cost of acquisition of the properties acquired during the year ended June 30, 1998. On a cost per Mcfe of reserves the depletion, depreciation and amortization costs decreased by $0.15 per Mcfe, or 17%, primarily due to the effects of the non-cash writedowns of $35.0 million recorded at December 31, 1998 and $28.2 million recorded at June 30, 1998 to reflect the impact of lower oil and natural gas prices at those two dates. In accordance with generally accepted accounting principles, at a point in time coinciding with the quarterly and annual reporting periods, we must test the carrying value of our oil and natural gas properties, net of related deferred taxes, against the "cost center ceiling." The "cost center ceiling" is a calculated amount based on estimated reserve volumes valued at then-current realized prices held flat for the life of the properties discounted at 10% per annum plus the lower of cost or estimated fair value of unproved properties. If the carrying value exceeds the cost center ceiling, the excess must be expensed in that period and the carrying value of the oil and natural gas reserves lowered accordingly. Amounts required to be written off may not be reinstated for any subsequent increase in the cost center ceilings. EXTRAORDINARY LOSS. As a result of the placement of the $125 million of 12 1/2% senior notes in July, 1998 we unwound an interest rate hedge contract related to existing floating interest rate bridge loans at a cost of approximately $3.5 million. As the debt hedged was retired using the proceeds from the issuance of the senior notes, the costs of terminating the hedge was recognized as an extraordinary loss. NET LOSS. We have incurred losses since inception, including $47.5 million, or $1.51 per common share, for the year ended June 30, 1999, compared to $32.8 million, or $1.44 per share, for the year ended June 30, 1998. These losses are a reflection of the low oil and natural gas prices experienced during the year ended June 30, 1999 combined with our high leverage position. 37 39 LIQUIDITY AND CAPITAL RESOURCES General We have proposed a recapitalization plan that, if achieved, will significantly improve our highly leveraged position. The key components of the proposed recapitalization plan are: - a reverse stock split of every 156 outstanding shares of our common stock into one share; - the exchange of all preferred stock, all warrants exercisable for shares of common stock and all remaining unexercised common stock repricing rights for 732,500 shares of post reverse-split common stock; - a common stock public offering or private placement of up to 10,000,000 shares of post-reverse split common stock which would yield net proceeds to us of approximately $74 million; and - the repurchase of $75 million face value of our 12 1/2% senior notes for approximately $52.5 million. The completion of the recapitalization is subject to the satisfaction of numerous conditions, including the tender by holders of approximately $104 million principal amount of our senior notes pursuant to a cash tender offer and the successful completion of this offering generating net proceeds of at least $50 million. If we are able to complete the recapitalization, including this offering of common stock that yields net proceeds to us of $74 million, our company will: - obtain a discount on the repurchase of at least $75 million of our senior notes, thereby creating more than $21 million of additional equity value for our stockholders; - on a pro forma basis, reduce our debt by $93.5 million, thereby increasing annual cash flow available to fund growth by $10.9 million and reducing our interest cost per Mcfe by nearly 60%; - reduce our long-term debt to $50 million, which approximates 23% of our June 30, 2000 SEC PV-10 of $217 million; - eliminate all outstanding preferred stock; - eliminate the dilutive effects of current market price conversion and repricing rights held by some of our stockholders; - improve our liquidity by using a portion of the proceeds from this offering to pay down our senior working capital facility and modifying the indenture governing our senior notes to permit us to increase our senior working capital facility from $35 million to $60 million; and - be in a position to satisfy the listing requirements of the Nasdaq National Market with a goal of improving the visibility and liquidity of our common stock. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining as much financing flexibility as is practicable. Since we commenced our oil and natural gas operations, we have utilized a variety of sources of capital to fund our acquisitions, development and exploitation programs and our operations. 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 further development of our existing proved reserves as well as additional acquisitions. Historically cash from operations has not been sufficient to fund the further development of our existing proved reserves or to fund additional acquisitions. There can be no assurance that cash from operations will be sufficient in the future to cover all of these needs. We have planned development and exploitation activities for all of our major operating areas. 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 38 40 our credit facilities to raise cash to fund acquisitions or repay indebtedness previously incurred for acquisitions. 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 these sources will be available to us to meet our budgeted capital spending. Furthermore, our ability to borrow other than under the restated credit agreement dated as of October 22, 1999 with Ableco Finance LLP and Foothill Capital Corporation is subject to restrictions imposed by our credit agreement. If we cannot secure additional funds for our planned development and exploitation activities, then we will be required to delay or reduce substantially our development and exploitation efforts. Sources of capital CREDIT AGREEMENT. On October 22, 1999, we entered into a restated credit agreement with Ableco and Foothill. The restated credit agreement, in which we provide a first secured lien on all of our assets, allows for borrowings of up to $50 million, subject to borrowing base limitations, to fund, among other things, development and exploitation expenditures, acquisitions and general working capital. The restated credit agreement matures on October 22, 2001. There are no scheduled principal repayments. The restated credit agreement bears interest as follows: - when the borrowings are less than $25 million, bank prime plus 2%; - when the borrowings are $25 million or greater, bank prime plus 4.5%; and - on amounts securing letters of credit issued on our behalf, 3%. The interest rate as of September 30, 2000 under this agreement was 11.50% per annum. As of October 3, 2000, the maximum amount available to us under the credit agreement was $30 million, of which $14 million in borrowings and $9.3 million in letters of credit were outstanding. The funds available under our secured credit agreement are limited to the lesser of: - $50 million; - the borrowing base calculation, which is the sum of: (1) 65% of proved developed producing, (2) 45% of proved developed non-producing and (3) 40% of proved undeveloped from our reserve reports, updated monthly using the 5 year NYMEX strip price for crude oil and natural gas; and - the maximum amount of secured debt available under the senior notes indenture, which is currently $35 million; minus $5 million. Under the credit agreement we must obtain a release of the security interest held by our secured lenders before we can sell any of our oil or natural gas properties. In addition, we are limited to making capital expenditures of not more than $12 million in any 12 month period and not more than $18 million between July 1, 1999 and October 22, 2001, the maturity date of the credit agreement. As of June 30, 2000 we had recorded capital expenditures totaling approximately $7 million against this limitation. SENIOR NOTES. On July 8, 1998, we completed a private placement of $125 million principal amount of 12 1/2% senior notes due 2008. In addition, on July 8, 1998 and July 20, 1998, we completed the private placement of $31.0 million of common stock. Pursuant to the note placement, we issued and sold the notes to institutional buyers pursuant to Rule 144A and Regulation D promulgated under the Securities Act of 1933. The notes mature on July 1, 2008, and 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 1/2% per annum. The payment of the notes is guaranteed by the parent company's three operating subsidiaries. Our 12 1/2% senior notes limit our ability to incur indebtedness. Currently, our maximum permitted indebtedness is limited to $50 million, of which $35 million may be secured in priority to the 12 1/2% senior notes. To incur indebtedness in excess of $50 million, we must be able to demonstrate that we have, on a 39 41 pro-forma basis over the last 12 months, an interest coverage ratio (EBITDA divided by cash interest expense) of greater than 2.5 times. Our senior notes indenture also provides that our senior secured debt, including the debt under our credit agreement, may exceed $35 million if the amount over $35 million is incurred pursuant to the acquisition of additional assets and the terms of the financing of that acquisition require that we provide a security interest on the acquired assets. As part of the recapitalization, we are seeking an amendment to the senior notes indenture to the permitted indebtedness limitations of the indenture. This amendment would provide for a dollar for dollar increase in the maximum permitted indebtedness to the extent that the equity raised pursuant to the recapitalization and thereafter, exceeds $50 million, net of all costs related to the equity issuance up to a maximum of $60 million. The permitted amount of senior secured indebtedness would increase in the same manner as the maximum permitted indebtedness. HEDGING ARRANGEMENTS AND LETTERS OF CREDIT. Some of our hedging arrangements contain a "cap" whereby we must pay the counter-party if oil or natural gas prices exceed the specified price 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 letters of credit required under the hedging arrangements is a function of the market value of oil and natural gas prices and the volumes of oil and natural gas subject to the hedging contract. As a result, the amount of the 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 our remaining available funds under our credit agreement. We recently amended our credit agreement to permit up to $12 million in letters of credit. As of September 30, 2000, we have provided $6.2 million in letters of credit to Enron, the counter-party to our hedge contracts containing "caps." As of September 30, 2000, we had an additional $14 million in outstanding loans and an unused availability of $9.8 million. On October 3, 2000, Enron made a margin call and requested that we increase the amount of the letters of credit to approximately $9.4 million, which will decrease the unused availability under our credit agreement to approximately $6.6 million. EQUITY CAPITAL. From inception through June 30, 2000 we have raised in excess of $58 million, net of $7.3 million in treasury stock, in equity. After completing the recapitalization, there will be 1,250,000 shares of our common stock outstanding in addition to the shares of common stock issued in this offering. The equity offering contemplated by this prospectus involves raising an additional $74 million, net of costs (at an assumed price of $8.00 per share), for 10,000,000 shares of our common stock. As a result, after completion of this offering and the recapitalization, we expect to have 11,250,000 shares of our common stock outstanding. DIVIDENDS. 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. 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 has been through the development and exploitation of our oil and natural gas properties. In either case, these activities require significant capital investments. While our earnings before non-cash charges have been positive since 1997, we have not been able to generate sufficient cash from this internal source to fund the replacement of our reserves consumed by production without relying on external sources of capital. We expect to spend $13.7 million on discretionary capital expenditures through June 2001 for exploitation, development and exploration projects, depending on the availability of funds. As of September 30, 2000 we are contractually obligated to fund $4.2 million in capital expenditures through June 2001. 40 42 If we are able to complete the recapitalization and this offering of common stock that yields net proceeds to us of $74 million, our company will: - purchase $75 million of our senior notes; - pay down our senior working capital facility; and - use any remainder for working capital purposes. We continue to evaluate acquisition opportunities; however, there are no existing agreements regarding any acquisitions. An acquisition may require the issuance of additional debt and or equity securities. There are no assurances that we will be able to obtain additional financing, or that any financing, if obtained, will be on terms favorable to us. INFLATION During the past several years, we have experienced moderate increases in property acquisition and development costs. During the fiscal year ended June 30, 1999 we received somewhat lower commodity prices for the natural resources produced from our properties. Oil and natural gas prices have increased during the year ended June 30, 2000. Our results of operations and cash flow have been, and will continue to be, affected somewhat by the volatility in oil and natural gas prices. If 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 and development 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. During the period from July 1, 1998 through June 30, 2000, West Texas Intermediate spot crude oil prices averaged $20.22 per barrel and traded between a low of $10.73 per barrel and a high of $34.65 per barrel. During the same period, Henry Hub spot natural gas prices averaged $2.41 per Mcf and traded between a low of $1.04 per Mcf and a high of $4.59 per Mcf. The tables below set out our weighted average price per barrel of oil, the weighted average price per Mcf of natural gas, the impact of our hedging programs and the related NYMEX indices.
JUNE 30, ------------------------ 1998 1999 2000 ------ ------ ------ NATURAL GAS (PER MCF): Average price received at wellhead.......................... $ 2.24 $ 2.00 $ 2.69 Effect of hedge contracts on average price.................. 0.03 0.13 (0.10) ------ ------ ------ Average price received, including hedge contracts........... $ 2.27 $ 2.13 $ 2.59 Average NYMEX Henry Hub..................................... $ 2.46 $ 2.01 $ 2.78 Average basis differential including hedge contracts........ (0.19) 0.12 (0.19) Average basis differential excluding hedge contracts........ $(0.22) $(0.01) $(0.09) OIL (PER BARREL): Average price received at wellhead.......................... $15.07 $12.37 $24.86 Average effect of hedge contract............................ 0.45 0.00 (2.10) ------ ------ ------ Average price received, including hedge contracts........... $15.52 $12.37 $22.76 Average NYMEX Sweet Light Oil............................... $17.62 $14.45 $25.90 Average basis differential including hedge contracts........ (2.10) (2.08) (3.14) Average basis differential excluding hedge contracts........ $(2.55) $(2.08) $(1.04)
41 43 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 Bank of Montreal and with an affiliate of Enron. 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, on approximately 73% of our expected natural gas production from reserves currently classified as proved developed producing during the fiscal year ending June 30, 2001. At the same time, we are able to participate completely in upward movements in the Henry Hub Nymex Index to the extent of approximately 76% of our expected natural gas production from reserves currently classified as proved developed producing for the fiscal year ending June 30, 2001. The operator of a significant natural gas producing property in which we hold a net profits interest sold natural gas under a fixed price contract for the period January 1 through early October 1999. Retrospectively, the prices for this contract, when compared to Henry Hub prices, were favorable during the three months ended March 31, 1999 but became unfavorable for the following six months. The fixed prices under this contract reduced the average wellhead price we received during the year ended June 30, 2000 by approximately $0.06 per Mcf. This fixed price contract expired during October 1999. We had a contract with an affiliate of Enron involving the hedging of a portion of our future natural gas production involving floor and ceiling prices as set out in the table below. We shared 50% of the price of NYMEX Henry Hub in excess of the ceiling price. This contract has expired. 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 ---------------- ------------- ------- ----- ------- September 1, 1997 August 31, 1998 600,000 $1.90 $2.66
We had a contract with an affiliate of Enron involving the hedging of a portion of our future oil production involving floor and ceiling prices as set out in the table below. We shared 50% of the price of NYMEX Henry Hub in excess of the ceiling price. This contract has expired. 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 ---------------- ------------- ------- ------ ------- September 1, 1997 August 31, 1998 120,000 $18.00 $20.40
Effective May 1, 1998 through October 31, 1999 we had a contract with Bank of Montreal involving the hedging of a portion of our future natural gas production 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 ---------------- ------------- ------- ----- ------- January 1, 1999 October 31, 1999 3,608,000 $2.00 $2.70
Effective November 1, 1999 we unwound the ceiling price limitation on our natural gas price hedging contract with Bank of Montreal at a cost of $3.3 million. 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) ---------------- ------------- --------- 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
42 44 The table below sets out the 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, 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 the 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, 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
The table below sets out the volume of oil hedged with a swap with Enron. All of these contracts have expired. The volumes presented in this table are divided equally over the months during the period:
VOLUME PERIOD BEGINNING PERIOD ENDING (BARRELS) PRICE PER BARREL ---------------- ------------- --------- ---------------- March 1, 1999 August 31, 1999 60,000 $13.50 April 1, 1999 September 30, 1999 30,000 $14.35 April 1, 1999 September 30, 1999 30,000 $14.82
The table below sets out the volume of oil hedged with a contract 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.
FLOOR CEILING VOLUME PRICE PER PRICE PER PERIOD BEGINNING PERIOD ENDING (BARRELS) BARREL BARREL ---------------- ------------- --------- --------- --------- 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
As of June 30, 2000 the fair market value of our hedging contracts, measured as the estimated cost we would incur to terminate the arrangements, was $5.3 million. As of June 30, 2000 a 10% increase in oil and natural gas prices would have resulted in an unfavorable change of $2.0 million in the fair market value of our hedging contracts and a 10% decrease in oil and natural gas prices would have resulted in a favorable change of $2.1 million in the fair market value of our hedging contracts. INTEREST RATE HEDGING We entered into a forward LIBOR interest rate swap effective for the period June 30, 1998 through June 29, 2009 at a rate of 6.30% on $125.0 million. We entered into this interest rate swap at a time when interest rates were rising. Our objective was to mitigate the risk of our having to pay higher than expected interest rates on what eventually became our 12 1/2% senior notes due 2008. The swap would have also served as an interest rate hedge on our indebtedness under the credit agreement and short term loans used to finance the April 1998 acquisition of our net profit and royalty interests if we failed to complete the private placement of the unsecured notes. Once the private placement of the 12 1/2% senior notes was completed, we determined that the interest rate swap no longer had any on-going value to us. On July 9, 1998, we unwound this swap at a cost to us of approximately $3.5 million, using a portion of the proceeds from the placement of our senior notes. This cost was expensed as an extraordinary loss during the year ended June 30, 1999. 43 45 BUSINESS GENERAL We are an independent energy company engaged in the exploration, development, exploitation and acquisition of on-shore oil and natural gas properties in conventional producing areas of North America. To date, we have grown almost exclusively through acquisitions of properties. As a result of our acquisitions we own a diverse property base concentrated in six producing areas or basins. Approximately 58% 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 June 30, 2000, we owned proved reserves of approximately 133 Bcf of natural gas and 2 MMBbls of oil aggregating to approximately 145 Bcfe with an SEC PV-10 value of $217 million and a reserve life index of 12.1 years. Approximately 68% of our proved reserves were classified as proved developed and approximately 92% of our proved reserves were natural gas. Our average daily net production for the month of June, was 30.6 MMcfe. At June 30, 2000, we had interests in 667 wells, including 83 service wells. Assuming completion of the recapitalization and this offering, we expect to be able to execute an annual capital expenditure program of approximately $20 million. As part of this program, we plan to increase our exploration expenditures and are currently having discussions with potential exploration joint venture partners. On a pro forma basis, we expect our cash flow to increase as a result of the $10.9 million decrease in annual interest expense that we anticipate from the completion of the recapitalization. Upon completion of this offering, the indenture governing our 12 1/2% senior notes will be amended to allow us to increase the level of permitted borrowings under our credit facility to $60 million. We anticipate that we can fund our capital expenditure program through a combination of working capital, operating cash flow and additional borrowings under our credit facility. Our properties are diversified over 6 asset areas located principally in the southwestern United States. Our interests in east and south Texas represent approximately 62% of our proved reserves on an SEC PV-10 basis at June 30, 2000. In addition, we own substantial properties in Kentucky, New Mexico and Oklahoma. At June 30, 2000 we had interests in leases covering approximately 177,000 gross, or 74,000 net, acres. We were incorporated under the laws of Delaware in 1989. The parent company is principally a holding company, holding the stock of its subsidiaries that own our assets and conduct our operations. Our principal 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. BUSINESS STRATEGY Our goal is to enhance stockholder value by expanding our oil and natural gas reserves, production levels and cash flow. Our strategy to achieve these goals consists of these elements: - Recapitalizing the company through a significant reduction of debt, a corresponding increase of equity and the elimination of all preferred securities; - Pursuing managed asset growth through: - actively developing and exploiting our existing higher potential oil and natural gas properties, particularly in south and east Texas; - 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; - an increased emphasis on exploration activities; and - targeted merger(s) where the consolidation with other companies will give us access to quality reserves within our core areas; 44 46 - Maintaining a capital and financial structure with a prudent debt to equity ratio that will allow us to use cash generated from operations to fund growth in our production and reserves; and - Enhancing our board of directors and management team through the addition of new industry senior executives to assist the company in improving and expanding its operating capacity and exploration activities. THE RECAPITALIZATION. Simultaneously with the closing of this offering, we will complete a recapitalization which includes: (a) a reverse stock split of every 156 outstanding shares of our common stock into one share; (b) the exchange of all preferred stock, all warrants exercisable for shares of common stock and all remaining 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. At our stockholders meeting on September 18, 2000, our stockholders approved the first two elements of the recapitalization. The repurchase of our 12 1/2% senior notes does not require stockholder approval. When the recapitalization and this offering are complete, our company will: - recognize a gain on the repurchase of $75 million of our senior notes at a discount, thereby creating more than $21 million of additional equity value for our stockholders; - on a pro forma basis, reduce our debt by $93.5 million, thereby increasing annual cash flow available to fund growth by $10.9 million and reducing our interest cost per Mcfe by nearly 60%; - reduce our long-term debt to $50 million, which approximates 23% of our June 30, 2000 SEC PV-10 of $217 million; - eliminate all outstanding preferred stock; - eliminate the dilutive effects of current market price conversion and repricing rights held by some of our stockholders; - improve our liquidity by using a portion of the net proceeds of this offering to pay down our senior working capital facility and by modifying the indenture governing our senior notes to permit us to increase our senior working capital facility from $35 million to $60 million; and - be in a position to satisfy the listing requirements of the Nasdaq National Market with a goal of improving the visibility and liquidity of our common stock. Upon completion of the recapitalization and this offering, there will be outstanding 11,250,000 shares of our common stock, no shares of preferred stock and no repricing rights. The closing of this offering is a condition to the completion of the recapitalization, and the completion of the recapitalization is a condition to the completion of this offering. DEVELOPMENT AND EXPLOITATION OF EXISTING PROPERTIES. We have identified over 400 potential 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 and grow our reserves while maximizing the long-term return on our capital. Our opportunities include: - additional exploration of well-defined locations on existing properties such as in the J.C. Martin field in south Texas; - infill drilling on our producing properties such as in the Gilmer field in east Texas; - recompletion of existing wells in behind-pipe intervals such as in the Lopeno/Volpe field in south Texas; and - developing proved undeveloped reserves by drilling low risk, long lived natural gas wells in the shallow New Albany Shale formation in Kentucky. PROPERTY ACQUISITIONS AND DIVESTITURES. We will diligently pursue the acquisition of oil and natural gas properties that we believe will provide us with a combination of increased production, reserve growth and 45 47 exploration potential. Our focus will be on only those properties that can be acquired at prices that will enhance our overall return on capital. Although we are currently weighted towards gas reserves, we anticipate that we may return to a more even oil to natural gas ratio. 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 return on capital. 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. If we are able to complete the recapitalization, we expect to be able to attract other small capitalization oil and natural gas companies as merger or consolidation partners. We will be in an excellent position to make accretive acquisitions of other companies and, through this process, to use our strong balance sheet and cash flow to effect the recapitalization of suitable merger candidates that otherwise may not have access to capital. CAPITAL AND FINANCIAL STRUCTURE. Our objective is to use a portion of the net proceeds of this offering and internally generated cash flow to fund our exploration, development and exploitation programs. We believe that we can finance our acquisition opportunities at attractive prices with a combination of equity and debt. MANAGEMENT TEAM. With the completion of the recapitalization, we will have the financial capability to pursue our strategy of increased focus on operating those properties that we own and on exploration as a means to grow our assets. We intend to continue restructuring our management team to add to our engineering, geology and geophysical personnel. We also intend to add seasoned senior oil and gas industry executives with experience in building stockholder value and in the management of exploration and development projects. On October 6, 2000, Joseph T. Williams became a director and Chairman of the Board of our company. In addition, we expect that Jerry B. Davis and Robert L. Keiser will join our board of directors before the completion of the recapitalization and this offering. Biographical information for each of Messrs. Williams, Davis and Keiser is included in "Management." Messrs. Williams, Keiser and Davis have informed us that if we do not successfully complete either this public offering of common stock or other acceptable financing arrangements, they will resign from their positions with our company. We are also in the process of recruiting one additional outside, non-employee director whom we expect will join our board of directors within 90 days after the completion of the recapitalization and this offering. As part of the restructuring of our management team, Bruce I. Benn and Robert P. Lindsay will resign from our board of directors immediately following the successful completion of this offering. 46 48 PRINCIPAL OIL AND NATURAL GAS PROPERTIES The following table summarizes information with respect to each of our principal areas of operation at June 30, 2000.
PERCENT PERCENT OF TOTAL OF TOTAL TOTAL NATURAL PROVED TOTAL SEC SEC GROSS OIL GAS RESERVES PROVED PV-10 PV-10 WELLS (MBBLS) (MMCF) (BCFE)(1) RESERVES ($000S) (1) ----- ------- ------- --------- -------- -------- ------- East Texas Gilmer Field.................. 41 564 51,081 54.5 38% $ 78,438 36% South Texas J.C. Martin Field............. 84 -- 16,331 16.3 11% 36,305 17% Lopeno and Volpe Fields....... 25 60 7,663 8.0 6% 12,856 6% Other South Texas............. 128 236 2,585 4.0 3% 6,799 3% --- ----- ------- ----- --- -------- --- Total South Texas..... 237 296 26,579 28.3 20% 55,960 26% Kentucky (Appalachian Basin) Nasgas Field.................. 32 -- 36,665 36.6 25% 31,721 15% Permian Basin Caprock (Queen) Field......... 29 181 -- 1.1 1% 872 0% Other Permian Basin........... 11 324 234 2.2 1% 4,764 2% --- ----- ------- ----- --- -------- --- Total Permian Basin... 40 505 234 3.3 2% 5,636 2% Mid-Continent (25 fields)....... 207 318 16,256 18.2 12% 36,645 17% Other........................... 27 327 1,865 3.8 3% 8,972 4% --- ----- ------- ----- --- -------- --- Total................. 584 2,010 132,680 144.7 100% $217,372 100%
--------------- (1) The proved reserves and SEC PV-10 were estimated by our internal petroleum engineers. The following is an overview of our major fields, by area. East Texas GILMER FIELD. The Gilmer field consists of 41 natural gas wells that cover approximately 13,000 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, eventually expanding to 21 natural gas units. The reservoirs are characterized by low permeability, depletion drive mechanisms and require stimulation. Well spacing is currently four wells per 640 acre 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. At June 30, 2000, the Gilmer field contained 55 Bcfe of proved reserves, which represented approximately 38% of our total proved reserves and 36% of our SEC PV-10. Our average daily net production from the Gilmer field in June 2000 was approximately 7.8 MMcf of natural gas and 91 Bbls, aggregating 8.3 MMcfe. Three new wells were drilled in June, July and September 2000, and a fourth well is being drilled. Two additional proved undeveloped locations are scheduled to be drilled this year, which management believes will allow the operator to assess the need for further down spacing. Depending upon economic 47 49 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, or Devon'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 "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." At June 30, 2000, the J.C. Martin field contained 16 Bcfe of proved reserves, which represented approximately 11% of our total proved reserves and approximately 17.0% of our SEC PV-10. Our average daily net production from the J.C. Martin field in June 2000 was 13.4 MMcfe. 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 consist of 25 wells. All of the wells produce from multiple reservoirs in the Upper Wilcox formation. Cody Energy, LLC, or Cody, is the operator of the majority of the wells with Dominion Production & Exploration, Inc. operating the remainder. The Lopeno field covers over 6,000 acres and 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 is producing from the Middle Wilcox formation. Multiple Upper Wilcox zones are classified behind the pipe. Nine proved undeveloped locations have been identified in these fields. Until June 30, 2000, we owned a 66.66% net profits interest in Choctaw's working interests. 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-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. At June 30, 2000, immediately after the sale described in the preceding paragraph, the Lopeno and Volpe fields contained an estimated 8 Bcfe of proved reserves, which represented approximately 6% of our total proved reserves and approximately 6% of our SEC PV-10. Our average daily net production from the fields in June 2000 was 1.2 MMcf/d 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. 48 50 Kentucky NASGAS FIELD. We have a 75% working interest in approximately 44,000 gross acres in Meade, Hardin and Breckinridge Counties, Kentucky. There are currently 32 gross producing natural gas wells located on our leases in Meade County. We drilled 12 wells in this field during our first year of ownership. 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. At June 30, 2000, these properties contained 37 Bcfe of net proved reserves, which represents approximately 25% of our total proved reserves and approximately 15% of our SEC PV-10. We acquired these properties because we believe they have significant low risk development potential from relatively shallow formations. Natural gas reserves in the New Albany Shale formation are long-lived reserves, generally lasting over 40 years. Our average daily net production from the Nasgas field in June 2000 was 435 Mcf. New Mexico CAPROCK (QUEEN) FIELD. The Caprock (Queen) field was our first acquisition and consists of 29 oil wells, 57 water injection wells, 57 shut-in wells and 76 temporarily abandoned wells on approximately 14,200 gross acres located in Lea and Chaves Counties, New Mexico. The Caprock field produces from the "Artesia Red Sand" or Queen sandstone of Permian age at a depth of approximately 3,000 feet. Discovery and delineation wells were drilled from 1940 through 1949. Development wells were drilled between 1954 and 1956 within the productive limits of the field, which is approximately twenty miles long and three miles wide. Primary production was established on 40-acre spacing. Initial waterflood operations began in 1959 and 1960. We have a 100% working interest and an 82.6% revenue interest in two operating units, the Drickey Queen Sand Unit and the Westcap Unit, a 98.3% working interest and a 79.3% revenue interest in a third operating unit, the Rock Queen Unit, and a 100% working interest and a 90% revenue interest in the Trigg and Federal V leases. Our working interest partner, Texican, Inc., or Texican, owns 25% of our interest in 640 acres of the Drickey Queen Sand Unit and has an option to participate for 25% of our interest in future development activities in all of our units except for the Rock Queen Unit. These five properties comprise the central 14,200 acres of the approximately 26,000 productive acres that contain nine contiguous development units. We have an option on an additional 5,920 acres within the 26,000 productive acres. We temporarily shut the field in due to significantly low oil prices in late 1998 and early 1999. The field was returned to production in October 1999. Phase I of the program toward redeveloping the waterflood pattern has been implemented. This program consisted of drilling four single lateral water injection wells and one dual-lateral producing well. These five wells along with the production facilities and water injection plant constitute Phase I of the redevelopment program. Phase I incorporates 640 acres out of the approximate 20,000 acres we control in the Caprock field. We are the operator of this project. 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 207 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 six 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. 49 51 The net daily production from these properties in June 2000 was 146 BOPD and 5.6 Mcf, or 6.5 MMcfe. At June 30, 2000, the net proven reserves are estimated to be 18.2 Bcfe, which represented approximately 12% of our total proved reserves and 17% of our SEC PV-10. EXPLORATION, DEVELOPMENT AND EXPLOITATION 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 infill 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. The objective of our overall development and exploitation strategy is to achieve a balance between low risk workover and recompletion activities and moderate risk infill and extensional development wells. This exploitation/development strategy is intended to increase reserves while minimizing the risk of uneconomic projects. We have budgeted through the fiscal year ending June 30, 2001 approximately $3.8 million for exploratory drilling projects. During the year ended June 30, 2000, we participated in drilling 21 gross, or 6.9 net, wells, of which 15 gross, or 3.2 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 on 7 different fields and anticipate continued growth in drilling activities. At June 30, 2000, we had identified approximately 115 development locations and exploitation projects on our acreage. We expect to spend approximately $12.5 million on development locations and exploitation projects during the fiscal year ending June 30, 2001, depending on the availability of drilling capital. The following is a brief discussion of our primary areas of development and exploitation activity: East Texas SEGNO FIELD. During April 1999, with an effective date of November 1, 1998, we converted our 80% net profits interest in Prime Energy's working interest to an 80% working interest in the proved developed wells and a 50% working interest in all other proved and unproved locations. We believe this was necessary to encourage Prime Energy to take steps to develop the field more fully. We intend to continue participating with the operator, Prime Energy, in the development of the Segno field. Recent activity includes recompleting several wells and drilling a new well targeting reserves not yet produced from the Yegua and Wilcox formations. The operator continues to return wells that are off production back to service and to improve the field's facilities infrastructure. Several significant new prospects have been identified utilizing 2-D seismic data. We are participating in developing options to exploit these prospects. We have recently agreed to farm out the rights to drill a Middle Wilcox test in which we will retain a carried interest and a back in after payout. 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, five of which have been 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. We expect 10 additional wells to be drilled before June 30, 2001. 50 52 LOPENO/VOLPE FIELDS. We believe significant potential exists in the Lopeno/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. Four proved undeveloped locations have been identified in the Volpe field that would develop Upper Wilcox sands. We are currently working with the operator to pursue the necessary workovers and additional drilling. We anticipate our share of capital expenditures in the Lopeno/Volpe fields will be approximately $2.4 million through June 2001. 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 expect that the field will be developed in five phases. The first phase, consisting of 20 wells, was completed in 1996. The second phase, consisting of 12 wells, was completed in 1998. The remaining development drilling is scheduled to commence during our 2001 fiscal year. We expect to develop a total of 75 proven locations at an average cost to us of $64,000 per well. New Mexico CAPROCK (QUEEN) FIELD. Exploitation efforts at the Caprock (Queen) field consist primarily of a waterflood redevelopment project. We, with the assistance of independent engineering consultants, have evaluated several alternate development options. We plan to redevelop the Drickey Queen/Westcap Units using a line drive waterflood pattern. A total of five dual lateral horizontal producers will be drilled and 14 single lateral horizontal injection wells are slated to be drilled. Phase I of the program consists of four horizontal water injection wells and one dual lateral horizontal producer with an associated water injection plant and production facility and was recently implemented. Phase I fully developed one 640 acre section of the Drickey Queen Unit. We have entered into an agreement with Texican regarding Phase I. The agreement requires Texican to fund 50% of the first $2.0 million of the cost of Phase I. In consideration of this, Texican will earn a 25% working interest in Phase I in the Drickey Queen Unit. The Phase I program was implemented in the first quarter of 2000 and our share of the program cost $1.6 million. We have just begun injection and production operations in Phase I and do not have definitive results. 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 "Risk Factors -- Our profitability is highly dependent on the prices for oil and natural gas, which can be extremely volatile." 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 a policy 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 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Changes in prices and hedging activities." For the year ended June 30, 2000, Goldston Oil Corporation accounted for approximately 28% of our oil and natural gas sales, Coastal Oil and Gas, Inc. accounted for approximately 16% of our oil and natural gas sales, Devon Energy Corporation accounted for approximately 12% of our oil and natural gas sales, and Kaiser Francis Oil Company accounted for approximately 10% 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 51 53 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. The market for our oil and natural gas depends on factors beyond our control, including the: - price of imports of oil and natural gas; - the extent of domestic production and imports of oil and natural gas; - the proximity and capacity of natural gas pipelines and other transportation facilities; - weather; - demand for oil and natural gas; - the marketing of competitive fuels; and - the effects of state and federal regulations. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. OIL AND NATURAL GAS RESERVES The following tables summarize information regarding our estimated proved oil and natural gas reserves as of June 30, 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 June 30, 1998 and 1999 with respect to the Morgan Properties included in this prospectus are based upon reports prepared by Ryder Scott Company. The estimates, other than with respect to the Morgan Properties, at June 30, 1998 and 1999 included in this prospectus are based upon reports prepared by H.J. Gruy and Associates, Inc. The estimates at June 30, 2000 are based on reserve reports prepared by our internal petroleum engineers. 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:
JUNE 30, ------------------------ 1998 1999 2000 ------ ------ ------ Natural Gas (per Mcf)...................................... $ 2.40 $ 2.44 $ 4.45 Oil (per Bbl).............................................. $12.80 $17.11 $31.42
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 this 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 nor 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 52 54 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. 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 11 of the notes to consolidated financial statements included in this prospectus. 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 June 30, 2000. PROVED OIL AND NATURAL GAS RESERVES(1)
JUNE 30, ------------------------------ 1998 1999 2000 -------- -------- -------- Natural gas reserves (MMcf): Proved Developed Reserves................................. 120,998 94,614 86,348 Proved Undeveloped Reserves............................... 55,097 42,947 46,332 -------- -------- -------- Total Proved Reserves of natural gas...................... 176,095 137,561 132,680 Oil reserves (MBbl): Proved Developed Reserves................................. 5,298 2,138 1,868 Proved Undeveloped Reserves............................... 2,651 2,486 142 -------- -------- -------- Total Proved Reserves of oil.............................. 7,949 4,624 2,010 Total Proved Reserves (MMcfe):.............................. 223,788 165,299 144,740
SEC PV-10 OF PROVED RESERVES(1)(2)
JUNE 30, ------------------------------ 1998 1999 2000 -------- -------- -------- (IN THOUSANDS) Proved Developed Reserves................................. $131,200 $ 99,650 $163,982 Proved Undeveloped Reserves............................... 33,920 31,076 53,390 -------- -------- -------- Total SEC PV-10................................... $165,120 $130,726 $217,372
--------------- (1) The data shown at June 30, 1998 and June 30, 1999, excluding data with respect to the Morgan Properties at June 30, 1998 and June 30, 1999, is based upon reports prepared by H.J. Gruy and Associates, Inc. The data included with respect to the Morgan Properties at June 30, 1998 and June 30, 1999 is based upon reserve reports prepared by Ryder Scott Company. The data for June 30, 2000 is based upon reserve reports prepared by our internal petroleum engineers. (2) SEC PV-10 differs from the Standardized Measure set forth in the notes to our consolidated financial statements, which is calculated after provision for future income taxes. 53 55 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 June 30, 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 proved 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 June 30, 2000.
GROSS NET --------------------- ---------------------- NATURAL NATURAL OIL GAS TOTAL OIL GAS TOTAL --- ------- ----- ---- ------- ----- Texas............................................ 160 159 319 41.9 33.6 75.5 New Mexico....................................... 29 -- 29 28.5 -- 28.5 Louisiana........................................ 1 -- 1 1.0 -- 1.0 Oklahoma......................................... -- 148 148 0.0 19.0 19.0 Kentucky......................................... -- 32 32 -- 22.4 22.4 Other(1)......................................... 1 54 55 0.4 10.8 11.2 --- --- --- ---- ---- ----- Total.................................. 191 393 584 71.8 85.8 157.6 === === === ==== ==== =====
--------------- (1) Represents wells located in Kansas, Alabama and Wyoming. PRODUCTION ECONOMICS The following table sets forth operating information for the periods presented.
YEAR ENDED JUNE 30, -------------------------- 1998 1999 2000 ------ ------- ------- OPERATING DATA PRODUCTION VOLUMES: Natural gas (MMcf)....................................... 3,368 12,962 10,618 Oil (MBbl)............................................... 325 500 224 Total (MMcfe).................................. 5,318 15,960 11,960 AVERAGE SALES PRICE: Natural gas (per Mcf).................................... $ 2.27 $ 2.13 $ 2.59 Oil (per Bbl)............................................ 15.52 12.37 22.76 SELECTED EXPENSES (PER MCFE): Production taxes......................................... $ 0.12 $ 0.09 $ 0.12 Lease operating expense.................................. 1.07 0.49 0.47 General and administrative............................... 0.43 0.22 0.25 Depreciation, depletion and amortization(1).............. 0.89 0.74 0.71
--------------- (1) Represents depreciation, depletion and amortization of oil and natural gas properties only. 54 56 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 JUNE 30, ---------------------------------------- 1998 1999 2000 ----------- ------------ ----------- GROSS NET GROSS NET GROSS NET ----- --- ----- ---- ----- --- EXPLORATORY: Oil.................................................... 1 0.0 0 0.0 1 0.2 Natural gas............................................ 1 0.3 0 0.0 -- 0.0 Dry.................................................... 1 0.7 1 1.0 1 0.5 -- --- -- ---- -- --- Total........................................ 3 1.0 1 1.0 2 0.7 DEVELOPMENT: Oil.................................................... 5 2.1 1 0.2 1 0.8 Natural gas............................................ 10 2.6 26 9.9 13 2.2 Dry.................................................... 1 0.4 1 0.7 1 0.2 -- --- -- ---- -- --- Total........................................ 16 5.1 28 10.8 15 3.2 TOTAL: Oil.................................................... 6 2.1 1 0.2 2 1.0 Natural gas............................................ 11 2.9 26 9.9 13 2.2 Dry.................................................... 2 1.1 2 1.7 2 0.7 -- --- -- ---- -- --- Total........................................ 19 6.1 29 11.8 17 3.9
Between June 30, 2000 and September 30, 2000, we have drilled 5 gross, 1.2 net, wells which were successful, and we drilled, 1 gross, or 1.0 net, well that was a dry hole. At September 30, 2000 we were in the process of drilling 1 gross, 0.4 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 June 30, 2000.
DEVELOPED UNDEVELOPED ------------------- ------------------- GROSS NET GROSS NET -------- -------- -------- -------- Texas.............................................. 47,200 13,800 6,500 1,300 New Mexico......................................... 14,300 14,100 -- -- Louisiana.......................................... 300 300 6,100 3,300 Oklahoma........................................... 37,400 5,300 -- -- Kentucky........................................... 600 400 43,900 30,700 Other(1)........................................... 20,500 5,200 -- -- -------- -------- -------- -------- Total.................................... 120,300 39,100 56,500 35,300 ======== ======== ======== ========
--------------- (1) Represents acreage located in Colorado, Kansas, Alabama 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 55 57 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. 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, 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: - royalties and other burdens and obligations, expressed and implied, under oil and gas leases; - overriding royalties and other burdens created by the assignor or its predecessors in title; - 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; - liens that 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; - pooling, unitization and communitization agreements, declarations and orders; and - 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. 56 58 A substantial portion of our oil and natural gas property interests are 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 "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 57 59 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 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. The Railroad Commission of the State of Texas is considering adopting rules to prevent discriminatory transportation practices by intrastate natural gas gatherers and transporters by requiring the disclosure of rate information under varying conditions of service. We are not able to predict with certainty the effects, if any, of these regulations on our operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil and natural gas liquids. 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 58 60 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 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. Is it 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. See "Risk Factors." EMPLOYEES As of October 6, 2000, we had 18 full-time employees consisting of 8 officers and 10 support staff. Three of the employees are in Ottawa, Canada, 14 of the employees are located in the Dallas office, and 1 is 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. LITIGATION 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. See "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". 59 61 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. MANAGEMENT The following sets forth the names, ages and positions of our officers and directors.
NAME AGE CURRENT POSITION WITH COMPANY ---- --- ----------------------------- Joseph T. Williams................ 63 Chairman of the Board and Director Edward J. Munden.................. 49 Chief Executive Officer, President and Director Bruce I. Benn..................... 46 Executive Vice President and Director Chief Operating Officer, Executive Vice President and Robert P. Lindsay................. 57 Director V. Ed Butler...................... 44 Vice President, Asset Management Ronald Idom....................... 45 Vice President, Acquisitions William W. Lesikar................ 47 Chief Financial Officer and Vice President William A. Williamson............. 44 Vice President, Land
We have also identified two persons, Jerry B. Davis and Robert L. Keiser, who have agreed to join our board as outside, non-employee directors before the completion of the recapitalization and this offering. Our current directors will increase the size of our board and appoint the two additional directors to fill the newly created vacancies in accordance with our bylaws. We anticipate that Messrs. Davis and Keiser would also be appointed to the board's compensation committee and the audit committee. We are also in the process of recruiting one additional outside, non-employee director whom we expect will join our board within 90 days after the completion of the recapitalization and this offering. Messrs. Williams, Davis and Keiser have informed us that if we do not successfully complete either this public offering of common stock or other acceptable financing arrangements, they will resign from their positions with our company. As part of the restructuring of our management team, Bruce I. Benn and Robert P. Lindsay will resign from our board of directors immediately following the successful completion of this offering. Effective September 15, 2000, Ronald I. Benn resigned from our company. Mr. Benn had served as our Chief Financial Officer since 1995 and he is the brother of Bruce I. Benn, one of our directors and Executive Vice Presidents. We have entered into a severance agreement with Mr. Benn pursuant to which we will pay him a lump sum severance payment of $200,000 and provide Mr. Benn medical, dental and life insurance benefits coverage until June 30, 2002. Mr. Benn has agreed to make himself available to us at the rate of $1,000 per day for 3 months to assist us in the transition period with a replacement Chief Financial Officer. We have no obligation to use his services during this time. The severance agreement includes a mutual release, a confidentiality provision and a covenant that for one year Mr. Benn will not induce or solicit any of our employees to terminate employment with us. We also agreed to indemnify Mr. Benn to the full extent authorized by law for claims for which Mr. Benn may be liable as a former director, officer or employee of our company. The following biographies describe the business experience of our executive officers and directors. JOSEPH T. WILLIAMS was appointed director and Chairman of the Board on October 6, 2000. From July 1998 to August 1999, Mr. Williams served as President and Chief Executive Officer of MCN Investment Corporation, a diversified energy company with $2 billion in oil and natural gas, natural gas pipeline and electrical power assets. Prior to this, Mr. Williams served as President and Chief Executive Officer of MCNIC Oil and Gas Company, a broad-based exploration and production company, from August 1997 to July 1998. From June 1995 to February 1996, Mr. Williams served as Vice Chairman and Chief Executive Officer of Enserch Exploration, Inc., an oil and as exploration and production company. Mr. Williams holds a B.S. in Petroleum Engineering from the University of Texas at Austin. 60 62 EDWARD J. MUNDEN has been the President and a director of DevX since March 6, 1995 and has served as our Chief Executive Officer since May 1996. He served as our Chairman of the Board from October 1997 to October 6, 2000. Since 1989, he has been a director and co-founder of Capital House Corporation, or CHC, which is a Canadian venture capital firm located in Ottawa, Canada. Mr. Munden has held positions in the mining industry with Eldorado Nuclear Limited from 1980 to 1989, the manufacturing industry with Proctor and Gamble Company of Canada from 1978 to 1980, and the oil and natural gas industry with Union Oil of Canada Limited from 1974 to 1976. Mr. Munden is a professional geological engineer and holds a Bachelor of Science degree in Engineering and a Masters of Business Administration from Queens University in Kingston, Canada. BRUCE I. BENN has been an Executive Vice President and a director of DevX since March 1995. In 1989, he, together with Ronald I. Benn and Edward J. Munden, founded CHC and has been a director since then. From 1985 to 1993, he was Vice President and director of Corporation House Ltd., where he acted as an investment banker and a financial advisor to resource development, manufacturing and construction firms around the world. He is an attorney and holds a Masters of Law degree from the University of London, England, a Baccalaureate of Laws from the University of Ottawa, Canada, and a Bachelor of Arts in Economics from Carleton University in Ottawa, Canada. Ronald I. Benn, a former Chief Financial Officer of the Company, is the brother of Bruce I. Benn. As part of the restructuring of our management team, Mr. Benn will resign from our board of directors immediately following the successful completion of this offering. ROBERT P. LINDSAY joined DevX in 1994 and became Executive Vice President in September 1995 and Chief Operating Officer in May 1996. From 1973 until 1995 Mr. Lindsay was Chief Executive Officer of Lin-mour Drilling Company. Mr. Lindsay joined Helmerich & Payne, an oil and natural gas drilling and exploration company headquartered in Tulsa, Oklahoma, in 1965 and held increasingly senior positions with that company until 1973. Mr. Lindsay holds a Bachelor of Arts degree in Accounting from the University of Texas. As part of the restructuring of our management team, Mr. Lindsay will resign from our board of directors immediately following the successful completion of this offering. V. ED BUTLER joined DevX in June 1996 as Vice President, Operations. He has 22 years of experience in oil field engineering and operations. From 1993 to 1995, he was Executive Vice President for Echo Production, Inc. From 1982 to 1993 he held the position of Operations Manager for Triad Energy Corporation. He has also been a staff engineer for Blocker Exploration Company from 1980 to 1982 and an area production engineer for Texas Oil and Gas Corporation from 1978 to 1980. Mr. Butler holds an M.B.A. from the University of Texas, and a Bachelor of Science in Petroleum Engineering from Texas A&M University. RONALD IDOM joined DevX in January 1998 as Vice President, Acquisitions. He has over 24 years of experience in reservoir engineering and management. From 1991 to 1997, he was Manager Gas Supply for Delhi Gas Pipeline Corporation and Manager Engineering/Project Development from 1988 to 1991. From 1985 to 1988 he held the position of Chief Reservoir Engineer for TXO Production Corp. Both Delhi Gas Pipeline and TXO Production Corp. were subsidiaries of USX/Texas Oil & Gas Corporation. He also served as acquisition engineer for NRM Petroleum from 1983 to 1985; a self-employed petroleum consultant from 1980 to 1983 and held various engineering positions with Texas Oil and Gas Corporation from 1976 to 1980. Mr. Idom graduated from Texas A&M University in 1976 with a Bachelor of Science in Petroleum Engineering. WILLIAM W. LESIKAR joined DevX in June 1998 as Vice President, Finance and now serves as our Chief Financial Officer. Mr. Lesikar, a Certified Public Accountant, has 24 years of experience in finance and accounting with nearly 19 years in the oil and gas industry. From 1981 to 1998, Mr. Lesikar held increasing positions of authority with Lyco Energy Corporation of Dallas, Texas including Controller from 1981 to 1983, and Chief Financial Officer and Executive Vice President from 1988 to 1998. From 1978 to 1981, Mr. Lesikar was an audit manager and senior auditor with Arthur Young & Company, now known as Ernst & Young LLP. From 1976 to 1978, Mr. Lesikar was an auditor with Haskins & Sells, now known 61 63 as Deloitte & Touche LLP. Mr. Lesikar holds a Masters of Business Administration from Southern Methodist University and a Bachelor of Business Administration from University of Texas at Austin. WILLIAM A. WILLIAMSON joined DevX in March 1998 as Vice President, Land. He has over 20 years of experience in petroleum land management. From 1989 to 1998, he served as President of BAW Energy, Inc. BAW Energy, Inc. was formed primarily to provide oil and gas asset management from a land and legal perspective to independent oil and gas companies. Clients of BAW Energy, Inc. included INCO Oil Corporation, Janex Oil Co., Inc., Walter Exploration, Inc. and DevX. From 1979 to 1989, he was self-employed as an independent Petroleum Landman. Mr. Williamson holds a Bachelor of Business Administration in Finance from Texas A&M University. The following biographies describe the business experience of Mr. Davis and Mr. Keiser, who we expect will join our board of directors before the completion of the recapitalization and this offering. JERRY B. DAVIS has over 25 years' experience working with Otis Engineering Corporation, an oil field service company and a division of Halliburton, including serving as President and Chief Executive Officer from 1990 to 1993. From July 1993 to present, Mr. Davis has engaged in investment activities and ranching. Mr. Davis holds a Master of Business Administration from Southern Methodist University, a B.S. in Petroleum Engineering from Texas A&M University and has a degree in ranch management from Texas Christian University. ROBERT L. KEISER, 57, retired in June 1999 from his position as Chairman of Kerr-McGee Corp., an integrated energy company. Mr. Keiser also served as Chairman, Chief Executive Officer and President of Oryx Energy Company, an independent oil and natural gas exploration company, from 1994 to March 1999, when Oryx Energy Company merged with Kerr-McGee Corp. From 1988 to 1994, Mr. Keiser served in various capacities with Oryx Energy Company. Mr. Keiser currently serves as a director of HVIDE Marine Inc., a company engaged in the business of providing marine support and transportation services to the energy and chemical industry. Mr. Keiser holds a B.S. in Petroleum Engineering from The University of Missouri-Rolla. EMPLOYMENT AGREEMENT WITH JOSEPH T. WILLIAMS Effective October 6, 2000, we entered into an employment agreement with Joseph T. Williams. The initial term of the employment agreement is for 2 years but it will be automatically extended for a further term of 2 years on each anniversary date of the agreement unless, at least 60 days before the anniversary date we notify Mr. Williams that we will not be extending the term. Mr. Williams will receive a base salary of $250,000 per year. Each year during the term, our compensation committee will determine a target bonus for Mr. Williams for that year that will be in the range of between 20% and 120% of Mr. Williams' base salary. Determination of the actual bonus amount to be paid to Mr. Williams will be in the discretion of our board of directors and will depend in part of the performance of the company during the year but in any case will not be less than 20% of the base salary. If we terminate Mr. William's employment for reasons other than for cause or Mr. Williams terminates his employment for good reason, as those terms are defined in the contract, then we must pay Mr. Williams, in addition to any accrued but unpaid salary and bonus to which he may then be entitled, the sum of 1 year's base salary plus the greater of his target bonus for that year or the actual bonus paid or payable with respect to the previous year. If termination occurs for those reasons within 2 years of a change of control or Mr. Williams resigns for any reason during the 13th month following a change of control, then Mr. Williams will be entitled to receive 3 times that amount. If termination is for reasons other than for cause or Mr. Williams terminates his employment for good reason he will also be entitled to receive health benefits for 3 years after termination as well as any benefits he might then be entitled to under any supplemental retirement plan we may have in place at the time. In addition, all of Mr. Williams' unvested stock options will vest immediately or he may elect to receive the cash equivalent of any unexercised stock options. We have also agreed to make additional payments to indemnify Mr. Williams should the severance payments attract excise tax under Article 4999 of the Internal Revenue Code. 62 64 "Change of control" is defined to include a merger or sale of our company if we are not the surviving entity, the sale of all or substantially all of our assets, the approval by our stockholders of a plan of liquidation or dissolution, specified changes in the composition of our board of directors, the acquisition of beneficial ownership of an aggregate of 15% of the voting power of our outstanding voting securities by any person or group who beneficially owned at least 10% of the voting power on October 6, 2000, the acquisition of beneficial ownership of an additional 5% of the voting power by any person or group who beneficially owned at least 10% of the voting power on October 6, 2000, the execution by us and a stockholder of a contract that by its terms grants the stockholder or its affiliate, the right to veto or block decisions or actions of our board of directors, or the bankruptcy of our company. Neither the recapitalization approved by our stockholders at the annual meeting on September 18, 2000 nor the public offering contemplated by this registration statement will constitute a change of control for the purposes of Mr. William's employment agreement. Under the employment agreement, we agreed to issue to Mr. Williams options to purchase 250,000 shares of post-reverse split common stock. The exercise price for these options will be the public offering price per share of common stock in this offering. The grant of the options is subject to the approval by our stockholders of an amendment to our 1997 Incentive Equity Plan to increase the number of options that may be awarded under the plan. Fifty percent of these options will vest on each of the first two anniversary dates of the grant. If we fail to deliver the options or fail to receive stockholder approval before the first anniversary date of the contract, then we must pay Mr. Williams the cash equivalent of the options. In addition, we have also entered into an indemnification agreement with Mr. Williams. COMPENSATION OF NON-EMPLOYEE DIRECTORS The board of directors has adopted a policy whereby each non-employee director is paid an annual retainer fee of $18,000 plus meeting fees of $1,000 for each board of directors meeting and $1,000 for each committee meeting (other than telephonic meetings) attended by the director unless the committee meeting is held on the same day as a board meeting, in which case the fee is $500. The company also reimburses its directors for travel, lodging and related expenses they may incur attending board of directors and committee meetings. In addition, subject to stockholder approval of an amendment to our directors' nonqualified stock option plan to increase the number of shares subject to the plan, we will grant each non-employee director options to purchase 3,000 shares of common stock upon the director's joining our board and options to purchase 3,000 shares for each year of service on our board. The price of shares that may be purchased upon exercise of an option will be the fair market value of the common stock on the date of grant. With respect to the initial grant of options to Messrs. Davis and Keiser, the exercise price will be the public offering price per share of common stock in this offering. If we do not obtain stockholder approval of the amendment to the option plan, then we will pay the directors the cash equivalent of the options. In addition, we will enter into indemnification agreements with our non-employee directors. 63 65 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth information with respect to the number of shares of common stock and voting stock (includes Series A preferred stock which is entitled to vote on all matters submitted to a vote by the holders of common stock) beneficially owned as of July 21, 2000, by (1) all holders of shares of common stock and voting stock known by the company to own beneficially more than 5% of the outstanding shares of any class of the voting stock, (2) the executive officers of the company, (3) each director of the company and (4) all directors and executive officers of our company as a group.
AMOUNT AND APPROXIMATE PRO FORMA AMOUNT PRO FORMA NATURE PERCENTAGE OF AND NATURE OF APPROXIMATE OF BENEFICIAL VOTING STOCK BENEFICIAL PERCENTAGE OF OWNERSHIP OWNED BEFORE OWNERSHIP AFTER VOTING STOCK NAME AND ADDRESS BEFORE THE THE THE OWNED AFTER THE OF BENEFICIAL OWNER RECAPITALIZATION RECAPITALIZATION RECAPITALIZATION(1) RECAPITALIZATION(1) ----------------------------- ---------------- ---------------- ------------------- ------------------- OFFICERS AND DIRECTORS: Joseph T. Williams(2)(3)..... 0 * 0 * Edward J. Munden(3).......... 6,600,000(4) 7.4% 42,307(4) 0.38% Bruce I. Benn(3)............. 6,600,000(4) 7.4% 42,307(4) 0.38% Robert P. Lindsay(3)......... 6,614,286(4)(5) 7.4% 42,398(4)(5) 0.38% William W. Lesikar(3)........ 0 * 0 * All executive officers and directors as a group (5 persons)................... 6,614,286(4) 7.4% 42,398(4) 0.38% FIVE PERCENT STOCKHOLDERS: Joint Energy Development Investments Limited Partnership................ 12,234,952(6) 13.6% 229,391 2.04% 1400 Smith St Houston, Texas 77002-7361 EIBOC Investments Ltd........ 6,600,000(4) 7.3% 42,308(4) 0.38% Charlton House White Park Road Bridgetown, Barbados W.I. JNC Opportunity Fund, Ltd.... 13,947,161(7) 15.4% 292,193 2.60% c/o Encore Capital Management, LLC 12007 Sunrise Valley Drive, Suite 460 Reston, Virginia 20191
--------------- * Less than 1 percent. (1) Assumes that the recapitalization, the reverse stock split and this offering of 10,000,000 shares of common stock have occurred. (2) Does not include options to purchase 250,000 shares of post-reverse split common stock that our board has agreed to issue to Mr. Williams, subject to the approval by our board and our stockholders of an amendment to increase the number of shares issuable under our 1997 Incentive Equity Plan. (3) Executive officer and/or director. (4) Edward J. Munden, Ronald I. Benn and Bruce I. Benn have a beneficial interest in the shares of common stock owned by EIBOC Investments Ltd., or EIBOC. In addition, EIBOC has granted an irrevocable proxy to Messrs. Munden, Benn, Benn and Lindsay to vote 6,600,000 shares, or 42,308 post reverse split shares, owned of record by EIBOC. Accordingly, the 6,600,000 shares, or 42,308 post reverse split shares, owned of record by EIBOC have been included as beneficially owned by each of the foregoing individuals, and by all executive officers and directors as a group. (5) Mr. Lindsay acquired 14,286 shares, or 91 post reverse split shares, of common stock in the name of his children and disclaims any beneficial interest in these shares. 64 66 (5) Includes 9,600,000 shares of common stock issuable upon conversion of the 9,600,000 shares of Series A preferred stock and 2,634,952 shares of common stock. JEDI is a limited partnership, the general partner of which is Enron Capital Management Limited Partnership, which is an indirect wholly-owned subsidiary of Enron Corp. Upon the occurrence of certain events of default (as defined in our restated certificate of incorporation), JEDI, the holder of the Series A preferred stock, has the right to require us to repurchase the Series A preferred stock. (6) Includes 364,500 shares of pre-split common stock issuable upon exercise of warrants held by JNC Opportunity Fund, Ltd., or JNC. Also includes 283,827 shares of pre-split common stock held by Diversified Strategies Fund, L.P., under common management with JNC, and 10,500 shares of pre-split common stock issuable to Diversified Strategies Fund, L.P. upon exercise of warrants. Does not include 76,825,534 shares of pre-split common stock issuable to JNC and 1,688,355 shares of pre-split common stock issuable to Diversified upon exercise of repricing rights as of July 21, 2000 (computed without regard to the covenants in the securities purchase agreement limiting the number of shares of common stock an individual holder may beneficially own). 65 67 DESCRIPTION OF CAPITAL STOCK Our authorized capital stock consists of 100,000,000 shares of common stock and 50,000,000 shares of preferred stock. Immediately after this offering, we will have 11,250,000 shares of common stock outstanding and no shares of preferred stock outstanding. COMMON STOCK The holders of shares of common stock have full voting power for the election of directors and for all other purposes. Each holder of common stock has one vote for each share. The shares of common stock do not have cumulative voting rights. Subject to the rights of holders of any outstanding shares of preferred stock, holders of common stock are entitled to dividends in the amounts and at the times declared by our board of directors in its discretion out of funds legally available for the payment of dividends. Holders of common stock have no subscription, redemption, sinking fund, conversion or preemptive rights. The outstanding shares of common stock are fully paid and nonassessable. After payment is made in full to the holders of any outstanding shares of preferred stock in the event of any liquidation, our remaining assets and funds will be distributed to the holders of common stock according to their respective shares. For a description of provisions of our certificate of incorporation that could make it more difficult for a third party to acquire control of us, see "Risk Factors -- Our certificate of incorporation contains provisions that could discourage an acquisition or change of control of our company." PREFERRED STOCK At the direction of our board, we may issue shares of preferred stock from time to time. Our board of directors may, without any action by holders of the common stock: - adopt resolutions to issue preferred stock in one or more classes or series; - fix or change the number of shares constituting any class or series of preferred stock; and - establish or change the rights of the holders of any class or series of preferred stock. The rights any class or series of preferred stock may evidence may include: - general or special voting rights; - preferential liquidation or preemptive rights; - preferential cumulative or noncumulative dividend rights; - redemption or put rights; and - conversion or exchange rights. We may issue shares of, or rights to purchase, preferred stock the terms of which might: - adversely affect voting or other rights evidenced by, or amounts otherwise payable with respect to, the common stock; - discourage an unsolicited proposal to acquire us; or - facilitate a particular business combination involving us. Any of these actions could discourage a transaction that some or a majority of our stockholders might believe to be in their best interests or in which our stockholders might receive a premium for their stock over its then market price. TRANSFER AGENT AND REGISTRAR The transfer agent and registrar for the common stock is Continental Stock Transfer and Trust Company, 2 Broadway, New York, New York 10004. 66 68 SHARES ELIGIBLE FOR FUTURE SALE Upon completion of this offering and the recapitalization, we will have outstanding 11,250,000 shares of common stock, assuming no exercise of the underwriter's over-allotment option. Of the shares of common stock that will be outstanding after this offering, 11,207,602 shares will be freely tradable without restriction or further registration under the Securities Act except that any shares purchased by our "affiliates," as that term is defined in Rule 144 under the Securities Act, generally may be sold only in compliance with the limitations of Rule 144 described below and the shares acquired by some of our stockholders in the recapitalization will be subject to transfer restrictions described below in "Underwriting -- Future sales." All of the remaining 42,398 shares of common stock will be "restricted" securities as that term is defined in Rule 144. The "restricted" securities may not be resold unless they are registered under the Securities Act or are sold pursuant to an available exemption from registration, including Rule 144 under the Securities Act. Upon expiration of the lock-up agreements described below, 42,398 of the restricted shares will be eligible for resale at various times thereafter upon expiration of applicable holding periods. Restricted securities may be sold in the public market only if they qualify for an exemption from registration under Rule 144, including Rule 144(k), or Rule 701 under the Securities Act. RULE 144 In general, under Rule 144 as currently in effect, commencing 90 days after the date of this prospectus, a person who has beneficially owned shares of our common stock for at least one year is entitled to sell within any three-month period a number of shares that does not exceed the greater of: - 1% of the number of shares of common stock then outstanding, which is expected to be approximately 112,500 shares upon completion of this offering, assuming no exercise of the underwriters' over-allotment option or - the average weekly trading volume of the common stock on the Nasdaq National Market during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale, subject to the restrictions specified in Rule 144. Sales under Rule 144 are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. RULE 144(k) Under Rule 144(k), a person who is not one of our affiliates at any time during the three months preceding a sale and who has beneficially owned the shares proposed to be sold for at least two years is entitled to sell the shares under Rule 144(k) without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144. Therefore, unless otherwise restricted, Rule 144(k) shares may be sold immediately upon completion of this offering. 67 69 UNDERWRITING Subject to the terms and conditions of an underwriting agreement, the underwriters named below are acting through their representatives, Friedman, Billings, Ramsey & Co., Inc. and Stifel, Nicolaus & Company, Incorporated. The underwriters have agreed with us, subject to the terms and conditions of the underwriting agreement, to purchase from us the number of shares of common stock shown opposite their names below. Other than the shares covered by the over-allotment option, the underwriters are obligated to purchase and accept delivery of all the shares of common stock if any are purchased.
UNDERWRITER NUMBER OF SHARES ----------- ---------------- Friedman, Billings, Ramsey & Co., Inc. ..................... Stifel, Nicolaus & Company, Incorporated.................... Total............................................. 10,000,000 ==========
The underwriters propose initially to offer the shares of common stock in part directly to the public at the initial public offering price shown on the cover page of this prospectus and in part to dealers, including the underwriters, at this price less a discount not in excess of $ per share. The underwriters may allow, and such dealers may re-allow other dealers, a discount not in excess of $ per share. The following table shows the underwriting discounts and commissions to be paid to the underwriters by us. These amounts represent the public offering price per share minus the amount paid by the underwriters per share and are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares of common stock. The underwriters' compensation was determined through negotiations between their representatives and us. In addition, Friedman, Billings, Ramsey & Co., Inc., has performed services related to identifying and evaluating various strategic alternatives since August 1999 and will receive 2% of the gross proceeds of this offering as a fee for these services and reimbursement of its out-of-pocket expenses, including fees and disbursements of its legal counsel and petroleum consultant.
EXERCISE NO EXERCISE FULL EXERCISE -------- ----------- ------------- Total underwriting fees..................................... $ $ Underwriting fee per share................................
OVER-ALLOTMENT. The underwriters have an option, exercisable within 30 days after the date of this prospectus, to purchase up to an aggregate of 1,500,000 additional shares of common stock at the public offering price less the underwriting discounts and commissions. The underwriters may exercise this option solely to cover over-allotments, if any, made in this offering. If the underwriters exercise this option, each underwriter will purchase shares in approximately the same proportion as indicated in the table above. INDEMNITY. DevX has agreed to indemnify the underwriters against some types of liabilities, including liabilities under the Securities Act. DevX has also agreed to contribute to payments that the underwriters may be required to make with respect to any of those liabilities. In addition, we have agreed to make the underwriters insured parties under our directors and officers insurance policy prior to the consummation of the offering. FUTURE SALES. DevX, its officers and directors have agreed not to offer, pledge, sell, hedge or otherwise transfer or dispose of, directly or indirectly, any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock for a period of 180 days from the date of this prospectus. Transfers or dispositions can be made sooner with the prior written consent of Friedman, Billings, Ramsey & Co., Inc., which may be given at any time without public notice. During this 180-day period, we have agreed not to file any registration statement with respect to any shares of our common stock. In addition, the Series A preferred stockholder, each Series C preferred stockholder and each repricing rights holder has agreed in the recapitalization agreement signed as part of the recapitalization not to sell, on any given trading day during the six month period immediately following the closing date of 68 70 this offering, more than the percentage of total shares received by the holder equal to the percentage that the holder's shares comprise of the total number of all post reverse-split common shares outstanding immediately after the close of this offering. For example, a holder that ends up with 1% of our total shares outstanding after this offering shall be permitted to sell only up to 1% of the shares the holder owns on any given day within the six-month period after the closing of this offering. OFFERS IN OTHER JURISDICTIONS. Neither we nor the underwriters have taken any action that would permit a public offering of the shares of common stock offered by this prospectus in any jurisdiction other than the United States where action for that purpose is required. The shares of common stock offered by this prospectus may not be offered or sold, directly or indirectly, nor may this prospectus or any other offering material or advertisements related to the offer and sale of these shares of common stock be distributed or published, in any jurisdiction, except under circumstances that will result in compliance with the applicable rules and regulations of such jurisdiction. This prospectus is not an offer to sell or a solicitation of an offer to buy any shares of common stock offered hereby in any jurisdiction in which such an offer or solicitation is unlawful. DISCRETIONARY ACCOUNT SALES. Friedman, Billings, Ramsey & Co., Inc. has advised us that the underwriters do not expect discretionary sales by the underwriters to exceed five percent of the shares offered by this prospectus. STABILIZATION. In connection with this offering, the underwriters may engage in transactions in the over-the-counter market or otherwise that stabilize, maintain or otherwise affect the price of the common stock. Specifically, the underwriters may over allot this offering, creating a syndicate short position. In addition, the underwriters may bid for and purchase shares of common stock. In addition, Friedman, Billings Ramsey & Co., Inc., on behalf of the underwriters, may reclaim selling concessions allowed to an underwriter or dealer for distributing the common stock in the offering if the syndicate repurchases previously distributed shares of common stock to cover syndicate short positions, in stabilizing transactions or otherwise. These activities may stabilize or maintain the market price of the common stock above independent market levels. The underwriters are not required to engage in these activities and may discontinue any of these activities at any time. DETERMINATION OF OFFERING PRICE. Though immediately prior to this offering our common stock was quoted on the OTC Bulletin Board, the public offering price of the common stock in this offering is not based on the market price of our common stock but was determined by negotiations between us and the underwriters. Among the factors considered in determining the public offering price were: - prevailing market conditions, - our results of operations in recent periods, - the present stage of our development, - the market capitalizations and development stages of other companies that we and the underwriters believe to be comparable to us, and - estimates of our growth potential. LEGAL MATTERS The validity of the issuance of the shares of common stock offered by this prospectus will be passed on for us by Haynes and Boone, LLP. Certain legal matters relating to the common stock offered by this prospectus will be passed on by Fulbright & Jaworski L.L.P., as counsel for the underwriters. 69 71 ENGINEERS The estimates relating to our proved oil and natural gas reserves and future net revenues of oil and natural gas reserves as of June 30, 1998 and 1999 (other than with respect to the Morgan Properties) included in this prospectus and incorporated in this prospectus by reference to our Annual Report on Form 10-K for the year ended June 30, 2000 are based upon estimates of the reserves prepared by H.J. Gruy in reliance upon its reports and upon the authority of H.J. Gruy as experts in petroleum engineering. The estimates relating to our proved oil and natural gas reserves and future net revenues of oil and natural gas reserves at June 30, 1998 and 1999 with respect to the Morgan Properties included in this prospectus and incorporated in this prospectus by reference to our Annual Report on Form 10-K for the year ended June 30, 2000 are based upon estimates of the reserves prepared by Ryder Scott, independent consulting petroleum engineers, in reliance upon its report and upon the authority of Ryder Scott as experts in petroleum engineering. The estimates relating to our proved oil and natural gas reserve and future net revenues of oil and natural gas reserves as of June 30, 2000 were prepared by our internal petroleum engineers. EXPERTS Ernst & Young LLP, independent auditors, have audited our consolidated financial statements at June 30, 2000 and 1999, and for each of the three years in the period ended June 30, 2000, as set forth in their report. We have included our financial statements in the prospectus and elsewhere in the registration statement in reliance on Ernst & Young LLP's report, given on their authority as experts in accounting and auditing. WHERE YOU CAN FIND MORE INFORMATION This prospectus is part of a registration statement we have filed with the SEC relating to our common stock. As permitted by SEC rules, this prospectus does not contain all of the information we have included in the registration statement and the accompanying exhibits and schedules we filed with the SEC. You may refer to the registration statement, exhibits and schedules for more information about us and our common stock. In addition, we are required to file current reports, quarterly reports, annual reports, proxy statements and other information with the SEC. You can read and copy the registration statement, exhibits and schedules and other filings at the SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549, and at the SEC's regional offices located at 7 World Trade Center, 13th Floor, New York, New York 10048, and at Suite 1400, 500 West Madison Street, Chicago, Illinois 60661. You can obtain information about the operation of the SEC's Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address for that site on the world wide web is sec.gov. Our Internet site on the world wide web is qsri.com. Neither the information on our web site nor the SEC's web site is part of this prospectus and references in this prospectus to our web site or any other web site are inactive textual references only. 70 72 INCORPORATION BY REFERENCE The SEC allows us to "incorporate by reference" the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this prospectus. We incorporate by reference the documents listed below and filed with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934: - Annual Report on Form 10-K for the year ended June 30, 2000; - Current Report on Form 8-K dated September 18, 2000; and - The description of our common stock contained in our Registration Statement on Form 10-SB filed under Section 12 of the Securities Exchange Act of 1934. We will provide these filings to any person, including any beneficial owner, to whom this prospectus is delivered, at no cost, upon written or oral request to us as follows: 13760 Noel Road, Suite 1030 Dallas, Texas 75240-7336 Attn: William W. Lesikar Telephone: (972) 233-9906 You should rely only on the information incorporated by reference or provided in this prospectus. We have not authorized anyone else to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information in this prospectus is accurate as of any date other than the date on the front of those documents. 71 73 GLOSSARY The terms defined in this glossary are used throughout this prospectus. "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. "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. 72 74 "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 prospectus, 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 June 30, 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 June 30, 2000, or as otherwise indicated. "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 73 75 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 our 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 to, development and operations and all risks in connection therewith. 74 76 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, 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 June 30, 1999 and 2000.... F-3 Consolidated Statements of Operations for the Years ended June 30, 1998, 1999, and 2000............................. F-4 Consolidated Statements of Stockholders' Equity (Net Capital Deficiency) for the Years ended June 30, 1998, 1999, and 2000...................................................... F-5 Consolidated Statements of Cash Flows for the Years ended June 30, 1998, 1999, and 2000............................. F-6 Notes to Consolidated Financial Statements.................. F-7
F-1 77 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. (formerly Queen Sand Resources, Inc.) and subsidiaries as of June 30, 1999 and 2000, 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 June 30, 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. (formerly Queen Sand Resources, Inc.) and subsidiaries as of June 30, 1999 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2000, in conformity with accounting principles generally accepted in the United States. Dallas, Texas August 18, 2000 F-2 78 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
JUNE 30, --------------------------- 1999 2000 ------------ ------------ ASSETS Current assets: Cash...................................................... $ 9,367,000 $ 11,881,000 Accounts receivable....................................... 4,499,000 6,530,000 Note receivable from employee............................. 79,000 -- Other..................................................... 74,000 113,000 ------------ ------------ Total current assets........................................ 14,019,000 18,524,000 ------------ ------------ Property and equipment, at cost: Oil and gas properties, based on full cost accounting method................................................. 178,421,000 182,280,000 Other equipment........................................... 392,000 405,000 ------------ ------------ 178,813,000 182,685,000 Less accumulated depreciation and amortization............ (81,615,000) (90,160,000) ------------ ------------ Net property and equipment.................................. 97,198,000 92,525,000 Other assets................................................ 7,993,000 8,144,000 ------------ ------------ $119,210,000 $119,193,000 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.......................................... $ 1,419,000 $ 355,000 Accrued liabilities....................................... 9,681,000 9,596,000 Current portion of long-term obligations.................. 42,000 584,000 ------------ ------------ Total current liabilities................................... 11,142,000 10,535,000 Long-term obligations, net of current portion............... 133,852,000 143,500,000 Commitments and contingencies Stockholders' equity (net capital deficiency): Preferred stock, $.01 par value: Authorized shares -- 50,000,000 at June 30, 1999 and 2000 Issued and outstanding shares -- 9,604,698 and 9,602,173 at June 30, 1999 and 2000, respectively.... 96,000 96,000 Aggregate liquidation preference -- $10,051,950 and $7,446,225 at June 30, 1999 and 2000, respectively Common stock, $.0015 par value: Authorized shares -- 100,000,000 at June 30, 1999 and 2000 Issued and outstanding shares -- 33,442,210 and 80,688,538 at June 30, 1999 and 2000, respectively... 65,000 135,000 Additional paid-in capital................................ 64,912,000 65,112,000 Accumulated deficit....................................... (83,606,000) (92,934,000) Treasury stock, at cost................................... (7,251,000) (7,251,000) ------------ ------------ Total stockholders' equity (net capital deficiency)..................................... (25,784,000) (34,842,000) ------------ ------------ Total liabilities and stockholders' equity........ $119,210,000 $119,193,000 ============ ============
See accompanying notes. F-3 79 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED JUNE 30, ----------------------------------------- 1998 1999 2000 ------------ ------------ ----------- Revenues: Oil and gas sales................................. $ 6,446,000 $ 4,591,000 $ 3,967,000 Net profits and royalty interests................. 4,432,000 23,140,000 22,990,000 Interest and other................................ 105,000 326,000 143,000 ------------ ------------ ----------- 10,983,000 28,057,000 27,100,000 Expenses: Production expenses............................... 4,547,000 3,196,000 1,372,000 Depreciation and amortization..................... 4,809,000 11,885,000 8,741,000 Hedge contract termination costs.................. -- -- 3,328,000 Write-down of oil and gas properties.............. 28,166,000 35,033,000 -- General and administrative........................ 2,259,000 3,533,000 3,026,000 Interest and financing costs...................... 3,956,000 18,352,000 18,561,000 ------------ ------------ ----------- 43,737,000 71,999,000 35,028,000 ------------ ------------ ----------- Loss before extraordinary item...................... (32,754,000) (43,942,000) (7,928,000) Extraordinary loss.................................. -- 3,549,000 1,130,000 ------------ ------------ ----------- Net loss............................................ $(32,754,000) $(47,491,000) $(9,058,000) ============ ============ =========== Loss before extraordinary item per common share..... $ (1.44) $ (1.40) $ (0.18) ============ ============ =========== Net loss per common share........................... $ (1.44) $ (1.51) $ (0.21) ============ ============ =========== Weighted average common shares outstanding.......... 22,719,177 31,434,465 43,465,423 ============ ============ ===========
See accompanying notes. F-4 80 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (NET CAPITAL DEFICIENCY) YEARS ENDED JUNE 30, 1998, 1999, AND 2000
PREFERRED STOCK COMMON STOCK ADDITIONAL TOTAL ------------------- --------------------- PAID-IN ACCUMULATED STOCKHOLDERS' SHARES AMOUNT SHARES AMOUNT CAPITAL TREASURY DEFICIT EQUITY --------- ------- ---------- -------- ----------- ----------- ------------ ------------- Balance at June 30, 1997................... 9,600,000 $96,000 20,825,552 $ 46,000 $14,474,000 $(5,000,000) $ (3,185,000) $ 6,431,000 Issuance of common stock for services... -- -- 150,000 -- 300,000 -- -- 300,000 Issuance of common stock for oil and gas properties........... -- -- 1,337,500 2,000 4,810,000 -- -- 4,812,000 Issuance of common stock for cash....... -- -- 2,010,715 3,000 4,883,000 -- -- 4,886,000 Issuance of convertible preferred stock and warrants to purchase common stock for cash................. 10,400 -- -- -- 9,544,000 -- -- 9,544,000 Net loss............... -- -- -- -- -- -- (32,754,000) (32,754,000) --------- ------- ---------- -------- ----------- ----------- ------------ ------------ Balance at June 30, 1998................... 9,610,400 96,000 24,323,767 51,000 34,011,000 (5,000,000) (35,939,000) (6,781,000) Issuance of common stock for oil and gas properties........... -- -- 8,740 -- 65,000 -- -- 65,000 Issuance of common stock for cash....... -- -- 3,845,241 6,000 23,668,000 -- -- 23,674,000 Issuance of common stock upon exercise of warrants............. -- -- 2,474,236 4,000 6,996,000 -- -- 7,000,000 Issuance of common stock pursuant to repricing rights............... -- -- 1,384,016 2,000 (2,000) -- -- -- Issuance of common stock on conversion of convertible preferred stock................ (3,550) -- 1,328,639 2,000 (2,000) -- -- -- Issuance of common stock as stock dividend............. -- -- 77,571 -- 176,000 -- (176,000) -- Repurchase of convertible preferred stock................ (2,152) -- -- -- -- (2,251,000) -- (2,251,000) Net loss............... -- -- -- -- -- -- (47,491,000) (47,491,000) --------- ------- ---------- -------- ----------- ----------- ------------ ------------ Balance at June 30, 1999................... 9,604,698 96,000 33,442,210 65,000 64,912,000 (7,251,000) (83,606,000) (25,784,000) Issuance of common stock pursuant to repricing rights..... -- -- 38,113,785 56,000 (56,000) -- -- -- Issuance of common stock on conversion of convertible preferred stock................ (2,525) -- 8,217,831 12,000 (12,000) -- -- -- Issuance of common stock as stock dividend............. -- -- 914,712 2,000 268,000 -- (270,000) -- Net loss............... -- -- -- -- -- -- (9,058,000) (9,058,000) --------- ------- ---------- -------- ----------- ----------- ------------ ------------ Balance at June 30, 2000................... 9,602,173 $96,000 80,688,538 $135,000 $65,112,000 $(7,251,000) $(92,934,000) $(34,842,000) ========= ======= ========== ======== =========== =========== ============ ============
See accompanying notes. F-5 81 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED JUNE 30, ------------------------------------------- 1998 1999 2000 ------------- ------------ ------------ OPERATING ACTIVITIES Net loss.......................................... $ (32,754,000) $(47,491,000) $ (9,058,000) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Extraordinary loss.............................. -- 3,549,000 1,130,000 Depreciation and amortization................... 4,809,000 13,354,000 10,288,000 Write-down of oil and gas properties............ 28,166,000 35,033,000 -- Unrealized foreign currency translation gains... (18,000) (19,000) (54,000) Issuance of common stock for services........... 300,000 -- -- Changes in operating assets and liabilities: Accounts receivable.......................... (4,580,000) 747,000 (1,952,000) Other assets................................. (45,000) (18,000) (39,000) Accounts payable and accrued liabilities..... 5,163,000 4,349,000 (1,149,000) ------------- ------------ ------------ Net cash provided by (used in) operating activities...................................... 1,041,000 9,504,000 (834,000) INVESTING ACTIVITIES Additions to oil and gas properties............... (154,242,000) (11,474,000) (7,410,000) Proceeds from sales of oil and gas properties..... -- 10,024,000 3,551,000 Net additions to other property and equipment..... (100,000) (161,000) (15,000) ------------- ------------ ------------ Net cash used in investing activities............. (154,342,000) (1,611,000) (3,874,000) FINANCING ACTIVITIES Proceeds from revolving credit facilities......... 103,000,000 12,300,000 26,898,000 Proceeds from (repayments on) bridge financing facilities...................................... 58,860,000 (58,860,000) -- Debt issuance costs............................... (4,898,000) (4,665,000) (1,957,000) Termination of LIBOR swap agreement............... -- (3,549,000) -- Payments on revolving credit facilities........... (15,358,000) (96,800,000) (16,398,000) Proceeds from issuance of 12 1/2% Senior Notes.... 121,000 125,000,000 -- Costs of proposed recapitalization................ -- -- (1,066,000) Redemption of DEM bonds........................... -- -- (213,000) Payments on notes payable......................... (2,064,000) (1,325,000) -- Proceeds from sale of convertible preferred stock and warrants to purchase common stock........... 9,544,000 -- -- Proceeds from the issuance of common stock........ 4,886,000 30,674,000 -- Repurchase of common and preferred stock.......... -- (2,251,000) -- Payments on capital lease obligation.............. (70,000) (80,000) (42,000) ------------- ------------ ------------ Net cash provided by financing activities......... 154,021,000 444,000 7,222,000 Net increase in cash.............................. 720,000 8,337,000 2,514,000 Cash at beginning of year......................... 310,000 1,030,000 9,367,000 ------------- ------------ ------------ Cash at end of year............................... $ 1,030,000 $ 9,367,000 $ 11,881,000 ============= ============ ============
See accompanying notes. F-6 82 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 1998, 1999, AND 2000 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General DevX Energy, Inc. (formerly Queen Sand Resources, Inc.) (DevX or the Company) was formed on August 9, 1994, under the laws of the State of Delaware. At June 30, 2000, EIBOC Investments Ltd. (EIBOC) held approximately 6,600,000 shares of the Company's common stock, par value $.0015 per share (Common Stock), representing approximately 7% of the Company's outstanding shares of Common Stock on a fully diluted basis. Certain officers of the Company have beneficial interests in EIBOC (see Note 5). Joint Energy Development Investments Limited Partnership (JEDI), an affiliate of Enron Corp. (Enron), holds approximately 13% of the Company's voting capital stock on a fully diluted basis. 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, Louisiana, New Mexico, Oklahoma, and Texas. The Company is highly leveraged. At June 30, 2000, the Company's ratio of total indebtedness to total capitalization was 132%. The Company's revenues, profitability, and ability to repay its indebtedness and related interest charges are highly dependent upon 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 prices of oil and natural gas, the Company has entered into certain hedging arrangements (see Note 4). However, a sustained period of depressed oil and natural gas prices could have a material adverse effect on the Company's results of operations and financial condition. The Company has proposed a recapitalization of the Company, which would include: (i) A reverse stock split of one common share for every 156 shares of common stock outstanding (ii) The exchange of all outstanding convertible preferred stock and warrants and repricing rights exercisable for shares of the Company's common stock for 732,500 shares of post reverse split common stock (see Note 5) (iii) The repurchase of $75 million face value of the Company's 12 1/2% Senior Notes for approximately $49 million with a portion of the net proceeds from a public offering of common stock There can be no assurance that the Company will be able to successfully complete the proposed recapitalization or the proposed public offering. 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 $721,000, $931,000, and $706,000 for the years ended June 30, 1998, 1999, and 2000, respectively. Capitalized costs are amortized by the unit-of-production method using estimates of proved F-7 83 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 years ended June 30, 1998 and 1999, the Company recorded full cost ceiling write-downs of $28,166,000 and $35,033,000, respectively. 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 are depreciated over the lease term. Costs incurred to operate, repair, and maintain wells and equipment are charged to expense as incurred. 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 Income taxes are accounted for under the asset and liability method, under which deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the F-8 84 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 and 1999, the Company issued an aggregate of 1,337,500 and 8,740 shares of Common Stock, respectively, valued at $4,812,000 and $65,000, respectively, in connection with the acquisitions of certain interests in oil and gas properties. During 1998, in connection with certain promotional services rendered by an unrelated party, the Company issued 150,000 shares of Common Stock valued at $300,000. Net Loss Per Common Share Net loss per common share is presented in accordance with Statement of Financial Accounting Standards No. 128, Earnings Per Share, which requires companies to present basic earnings per share calculated based on the weighted average number of common shares outstanding during the period, and, if applicable, diluted earnings per share which 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 June 30, 1998, 1999, and 2000, the loss per common share data is based on the weighted average common shares outstanding and excludes the effects of the Company's potentially dilutive securities (see Note 5). 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. Concentrations of Credit 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 June 30, 1998, two oil and gas companies accounted for 17% and 13%, respectively, of the Company's oil and gas sales. For the year ended June 30, 1999, four oil and gas companies accounted for 30%, 12%, 11%, and 9%, respectively, of the Company's oil and gas sales. For the year ended June 30, 2000, four oil and gas companies accounted for 28%, 16%, 12%, and 10%, respectively, of the Company's 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. F-9 85 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 years ended June 30, 1998, 1999, and 2000, there were no differences between the Company's net losses and total comprehensive income. Derivatives The Company utilizes certain derivative financial instruments to hedge future oil and gas prices and interest rate risk (see Note 4). Gains and losses arising from the use of the instruments are deferred until realized. Gains and losses from ongoing settlements of hedges of oil and gas prices are reported as oil and gas sales. Gains and losses from ongoing settlements of interest rate hedges are reported in interest expense. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, which will be adopted by the Company effective July 1, 2000. The Statement will require the Company to recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value through income. If the derivative is a hedge, depending on the nature of the hedge, changes in the fair value of derivatives will either be 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. The ineffective portion of a derivative's change in fair value will be immediately recognized in earnings. Based on the Company's derivative positions at June 30, 2000, the Company estimates that, upon adoption, it will report a gain from the cumulative effect of adoption of approximately $413,000, and a reduction in other comprehensive income of $5,907,000. 2. ACQUISITIONS On April 20, 1998, the Company acquired certain nonoperated net profits interests and royalty interests (collectively, the Morgan Properties) for net cash consideration of approximately $137.9 million from pension funds managed by J.P. Morgan Investments (the Morgan Property Acquisition). The Morgan Property Acquisition was financed with borrowings under the Company's previous credit agreement and two subordinated bridge credit facilities (see Note 3). The results of operations of the Morgan Properties have been included in the consolidated financial statements from the date of acquisition. 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-10 86 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Presented below are the oil and gas sales and associated production expenses associated with the Morgan Properties, which are presented in the accompanying consolidated statements of operations for the years ended June 30, 1998, 1999 and 2000, respectively, as net profits and royalty interests revenues.
YEAR ENDED JUNE 30, -------------------------------------- 1998 1999 2000 ---------- ----------- ----------- Oil and gas sales.............................. $6,219,000 $29,071,000 $28,715,000 Production expenses............................ 1,787,000 5,931,000 5,725,000 ---------- ----------- ----------- Net profits and royalty interests.............. $4,432,000 $23,140,000 $22,990,000 ========== =========== ===========
3. CURRENT AND LONG-TERM DEBT A summary of current and long-term debt follows:
JUNE 30, --------------------------- 1999 2000 ------------ ------------ 12 1/2% Senior Notes, due July 2008...................... $125,000,000 $125,000,000 12% unsecured DEM bonds, due July 2000................... 852,000 584,000 Revolving credit agreement............................... 8,000,000 18,500,000 Capital lease obligations................................ 42,000 -- ------------ ------------ 133,894,000 144,084,000 Less current portion of debt and capitalized lease obligation............................................. 42,000 584,000 ------------ ------------ Total long-term obligations.................... $133,852,000 $143,500,000 ============ ============
On April 17, 1998, the Company entered into an amended and restated credit agreement with Bank of Montreal and certain affiliates of JEDI. During October 1999, the Company entered into an amended and restated revolving credit agreement (the Credit Agreement) with new lenders, replacing the existing lender group. The Credit Agreement allows the Company to borrow up to $30 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. Borrowings under the Credit Agreement totaled $18.6 million at June 30, 2000. The interest rate at June 30, 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 of 1.0X, based on the last twelve-month operating results. At June 30, 2000, the Company was in compliance with these covenants. Letters of credit up to a maximum of $7.5 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 under the Credit Agreement. At June 30, 2000, the Company had a letter of credit outstanding in the amount of $6.2 million to an affiliate of Enron to secure a swap exposure (see Note 4). As of June 30, 1999, $8,000,000 was outstanding under the Company's previous credit agreement. 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 unamortized deferred costs of the previous agreement. On July 8, 1998, the Company completed a private placement of $125,000,000 principal amount of 12 1/2% 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 1/2% per annum. The F-11 87 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. 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 and DEM 1,200,000 were outstanding at June 30, 1999 and 2000, respectively. On July 15, 2000, the Company retired all remaining outstanding notes for approximately $584,000. During the years ended June 30, 1998, 1999, and 2000, the Company made cash payments of interest totaling approximately $3,946,000, $9,105,000, and $16,944,000, respectively. 4. 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. The Company had a collar with an affiliate of JEDI 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 years ended June 30, 1998 and 1999, the Company recognized net hedging gains of approximately $120,000 and $85,000, respectively, relating to these agreements, which are included in oil and gas sales. The Company has implemented a comprehensive hedging strategy for its natural gas production over the next few years. The table below sets out volumes of natural gas hedged with a floor price of $1.90 per MMBtu with Enron, an affiliate of JEDI, which received a fee of $478,000 during the year ended June 30, 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
F-12 88 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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) ---------------- ------------- --------- 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 May 1, 1998 through October 31, 1999, the Company had a collar with Bank of Montreal involving the hedging of a portion of future natural gas production 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 ---------------- ------------- --------- ----- ------- May 1, 1998........................... December 31, 1998 3,540,000 $2.00 $2.70 January 1, 1999....................... October 31, 1999 3,608,000 2.00 2.70
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 the volume 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...................................... April 30, 2001 990,000 May 1, 2001.......................................... December 31, 2001 1,980,000 January 1, 2002...................................... April 30, 2002 850,000 May 1, 2002.......................................... December 31, 2002 1,700,000 January 1, 2003...................................... December 31, 2003 2,250,000
During the years ended June 30, 1998, 1999, and 2000, the Company recognized hedging gains (losses) of approximately $122,000, $1,690,000, and $(981,000), respectively, relating to these agreements, which are included in net profits and royalty interests revenues. During the year ended June 30, 1999, the Company entered into a swap agreement with an affiliate of JEDI 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 June 30, 1999, the Company entered into a swap agreement with an affiliate of JEDI 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 years ended June 30, 1999 and 2000, the Company recognized hedging losses of approximately F-13 89 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) $231,000 and $358,000, respectively, relating to this agreement which are included in net profits and royalty interests revenues. The table below sets out the volume 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 year ended June 30, 2000, the Company recognized hedging losses of approximately $112,000 relating to this contract. 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 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 June 30, 1999. 5. STOCKHOLDERS' EQUITY General The Company's Certificate of Incorporation authorizes issuance of: (i) 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 (ii) 100,000,000 shares of Common Stock. During the year ended June 30, 1998, 10,400 shares of Preferred Stock were designated and issued as Series C Preferred Stock. 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. Capital Stock Purchase Agreements In March 1997, the Company entered into a Securities Purchase Agreement (the JEDI Purchase Agreement) with JEDI and a Securities Purchase Agreement (the Forseti Purchase Agreement) with Forseti Investments Ltd. (Forseti). In May 1997, pursuant to the JEDI Purchase Agreement, JEDI acquired 9,600,000 shares of Series A Participating Convertible Preferred Stock, par value $0.01 per share, of the Company (the Series A Preferred Stock), certain warrants to purchase Common Stock, and nondilution rights as in regard to future stock issuances. The aggregate consideration received by the Company consisted of $5,000,000 ($0.521 per share). F-14 90 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In connection with the issuance of the Series A Preferred Stock, the Company granted JEDI certain maintenance rights and certain demand and piggyback registration rights with respect to the shares of Common Stock issuable upon conversion of the Series A Preferred Stock. Pursuant to the terms of the Series A Preferred Stock, JEDI may designate a number of directors to the Company's Board of Directors, such that the percentage of the number of directors that JEDI may designate approximates the percentage voting power JEDI has with respect to the Company's Common Stock. In addition, upon certain events of default (as defined in the Series A Certificate of Designation), JEDI will have the right to elect a majority of the directors of the Company and an option to sell the Series A Preferred Stock to the Company. In May 1997, pursuant to the Forseti Purchase Agreement, the Company repurchased 9,600,000 shares of Common Stock owned by Forseti in exchange for (i) $5,000,000 ($0.521 per share) cash, (ii) the issuance by the Company of Class A Common Stock Purchase Warrants to purchase 1,000,000 shares of Common Stock at an initial exercise price of $2.50 per share (the Class A Warrants) and Class B Common Stock Purchase Warrants to purchase 2,000,000 shares of Common Stock at an initial exercise price of $2.50 per share (the Class B Warrants, and together with the Class A Warrants, the Forseti Warrants), and (iii) certain contingent payments. Forseti had the option of either selling or exercising the Forseti Warrants or receiving the contingent payments. During the year ended June 30, 1998, Forseti elected to sell the warrants to a third party and, thus, lost the rights to receive any contingent payments. The JEDI Purchase Agreement contains certain positive and negative covenants. The Company was in compliance with all of the applicable covenants at June 30, 1999 and 2000. Pursuant to the JEDI Purchase Agreement, JEDI, EIBOC, and certain officers of the Company (Management Stockholders) entered into a Stockholders Agreement whereby JEDI, EIBOC, and the Management Stockholders agreed to certain restrictions on the transfer of shares of Common Stock held by EIBOC and the transfer of shares of Common Stock or securities convertible, exercisable, or exchangeable for shares of Common Stock held by JEDI. The Stockholders Agreement will terminate on the earlier of (i) the fifth anniversary of the date of the Stockholders Agreement or (ii) the date on which JEDI and its affiliates beneficially own in the aggregate less than 10% of the voting power of the Company's capital stock. Series A Preferred Stock The holders of shares of Series A Preferred Stock are generally entitled to vote (on an as-converted basis) as a single class with the holders of the Common Stock, together with all other classes and series of stock of the Company that are entitled to vote as a single class with the Common Stock, on all matters coming before the Company's stockholders. For so long as at least 960,000 shares of Series A Preferred Stock are outstanding, the following matters require the approval of the holders of shares of Series A Preferred Stock, voting together as a separate class: (i) The amendment of any provision of the Company's Certificate of Incorporation or the bylaws (ii) The creation, authorization, or issuance of, or the increase in the authorized amount of, any class or series of shares ranking on a parity with or prior to the Series A Preferred Stock either as to dividends or upon liquidation, dissolution, or winding up (iii) The merger or consolidation of the Company with or into any other corporation or other entity or the sale of all or substantially all of the Company's assets F-15 91 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (iv) The reorganization, recapitalization, or restructuring or similar transaction that requires the approval of the stockholders of the Company The holders of shares of Series A Preferred Stock have the right, acting separately as a class, to elect a number of members to the Company's Board of Directors. The number shall be a number such that the quotient obtained by dividing such number by the maximum authorized number of directors is as close as possible to being equal to the percentage of the outstanding voting power of the Company entitled to vote generally in the election of directors represented by the outstanding shares of Series A Preferred Stock at the relevant time. A holder of shares of Series A Preferred Stock has the right, at the holder's option, to convert all or a portion of its shares into shares of Common Stock at any time at an initial rate of one share of Series A Preferred Stock for one share of Common Stock. The Series A Certificate of Designation provides for customary adjustments to the number of shares issuable upon conversion in the event of certain dividends and distributions to holders of Common Stock, certain reclassifications of the Common Stock, stock splits, and combinations and mergers and similar transactions. The holders of the shares of Series A Preferred Stock are entitled to receive dividends (other than a dividend or distribution paid in shares of, or warrants, rights, or options exercisable for or convertible into or exchangeable for, Common Stock) when and if declared by the Board of Directors on the Common Stock in an amount equal to the amount each such holder would have received if such holder's shares of Series A Preferred Stock had been converted into Common Stock. The holders of Series A Preferred Stock will also have the right to certain dividends upon and during the continuance of an Event of Default. Upon the liquidation, dissolution, or winding up of the Company, the holders of the shares of Series A Preferred Stock, before any distribution to the holders of Common Stock, are entitled to receive an amount per share equal to $.521 plus all accrued and unpaid dividends thereon (Liquidation Preference). The holders of the shares of Series A Preferred Stock will not be entitled to participate further in the distribution of the assets of the Company. The Series A Certificate of Designation provides that an Event of Default will be deemed to have occurred if the Company fails to comply with any of its covenants in the JEDI Purchase Agreement, provided that the Company will have a 30-day cure period with respect to the non-compliance with certain covenants. Upon the occurrence but only during the continuance of an Event of Default, the holders of Series A Preferred Stock are entitled to receive, in addition to other dividends payable to holders of Series A Preferred Stock, when and if declared by the Board of Directors, cumulative preferential cash dividends accruing from the date of the Event of Default in an amount per share per annum equal to 6% of the Liquidation Preference in effect at the time of accrual of such dividends, payable quarterly in arrears on or before the 15th day after the last day of each calendar quarter during which such dividends are payable. Unless full cumulative dividends accrued on shares of Series A Preferred Stock have been or contemporaneously are declared and paid, no dividend may be declared or paid or set aside for payment on the Common Stock or any other junior securities (other than a dividend or distribution paid in shares of, or warrants, rights, or options exercisable for or convertible into or exchangeable for, Common Stock or any other junior securities), nor shall any Common Stock nor any other junior securities be redeemed, purchased, or otherwise acquired for any consideration, nor may any monies be paid to or made available for a sinking fund for the redemption of any shares of any such securities. Upon the occurrence and during the continuance of an Event of Default resulting from the failure to comply with certain covenants, the holders of shares of Series A Preferred Stock have the right, acting F-16 92 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) separately as a class, to elect a number of persons to the Board of Directors of the Company that, along with any members of the Board of Directors who are serving at the time of such action, will constitute a majority of the Board of Directors. Upon the occurrence of an Event of Default resulting from the failure to comply with certain covenants, each holder of shares of Series A Preferred Stock has the right, by written notice to the Company, to require the Company to repurchase, out of funds legally available therefor, such holder's shares of Series A Preferred Stock for an amount in cash equal to the Liquidation Preference in effect at the time of the Event of Default. Concurrently with the transfer of any shares of Series A Preferred Stock to any person (other than a direct or indirect affiliate of JEDI or other entity managed by Enron Corp. or any of its affiliates), the shares of Series A Preferred Stock so transferred will automatically convert into a like number of shares of Series B Preferred Stock. At June 30, 1998, 1999, and 2000, 9,600,000 shares of Series A Preferred Stock were outstanding. Series B Preferred Stock The Series B Certificate of Designation authorizes the issuance of up to 9,600,000 shares of Series B Preferred Stock. The terms of the Series B Preferred Stock are substantially similar to those of the Series A Preferred Stock, except that the holders of Series B Preferred Stock will not (i) have class voting rights except as required under Delaware corporate law, (ii) be entitled to any remedies upon an event of default, or (iii) be entitled to elect any directors of the Company, voting separately as a class. At June 30, 1998, 1999 and 2000, no shares of Series B Preferred Stock were outstanding. Series C Preferred Stock The holders of shares of Series C Preferred Stock are not entitled to vote with the holders of the Common Stock except as required by law or as set forth below. For so long as any shares of Series C Preferred Stock are outstanding, the following matters will require the approval of the holders of at least two-thirds of the then outstanding shares of Series C Preferred Stock, voting together as a separate class: (i) Alter or change the rights, preferences, or privileges of the Series C Preferred Stock or any other capital stock of the Company so as to affect adversely the Series C Preferred Stock (ii) Create any new class or series of capital stock having a preference over or ranking pari passu with the Series C Preferred Stock as to redemption, the payment of dividends or distribution of assets upon a Liquidation Event (as defined in the Series C Certificate of Designation) or any other liquidation, dissolution, or winding up of the Company (iii) Increase the authorized number of shares of Preferred Stock of the Company (iv) Re-issue any shares of Series C Preferred Stock which have been converted in accordance with the terms hereof (v) Issue any Senior Securities (other than the Company's Series B Preferred Stock pursuant to the terms of the Company's Series A Preferred Stock) or Pari Passu Securities (each, as defined in the Series C Certificate of Designation) (vi) Declare, pay, or make any provision for any dividend or distribution with respect to the Common Stock or any other capital stock of the Company ranking junior to the Series C Preferred Stock as to dividends or as to the distribution of assets upon liquidation, dissolution, or winding up of the Company F-17 93 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The holders of at least two-thirds of the then outstanding shares of Series C Preferred Stock can agree to allow the Company to alter or change the rights, preferences, or privileges of the shares of Series C Preferred Stock. Holders of the Series C Preferred Stock that did not agree to such alteration or change shall have the right for a period of thirty days following such change to convert their Series C Preferred Stock to Common Stock. A holder of shares of Series C Preferred Stock has the right, at the holder's option, to convert all or a portion of its shares into shares of Common Stock at any time. The number of shares of Common Stock into which a share of Series C Preferred Stock may be converted will be determined as of the conversion date according to a formula set forth in the Series C Certificate of Designation. Generally, the conversion rate is equal to the aggregate stated value of the shares to be converted divided by a floating conversion price that may not exceed $7.35 per share. On December 24, 2001, all shares of Series C Preferred Stock that are then outstanding shall be automatically converted into shares of Common Stock. The Series C Certificate of Designation provides for customary adjustments to the number of shares issuable upon conversion in the event of certain dividends and distributions to holders of Common Stock, certain reclassifications of the Common Stock, stock splits, combinations and mergers, and similar transactions and certain changes of control. The holders of the shares of Series C Preferred Stock are entitled to receive cumulative dividends, when and if declared by the Board of Directors, subject to the prior payment of any accumulated and unpaid dividends to holders of Senior Securities, but before payment of dividends to holders of Junior Securities (as defined in the Series C Certificate of Designation), on each share of Series C Preferred Stock in an amount equal to the stated value of such share multiplied by 5%. Upon the liquidation, dissolution, or winding up of the Company, the holders of the shares of Series C Preferred Stock, before any distribution to the holders of Junior Securities, and after payments to holders of Senior Securities, will be entitled to receive an amount equal to the stated value of the Series C Preferred Stock (subject to ratable adjustment in the event of reclassification of the Series C Preferred Stock or other similar event) plus any accrued and unpaid dividends thereon. The Company has the right to redeem all of the outstanding Series C Preferred Stock under certain conditions. Holders of Series C Preferred Stock have the right to tender shares for redemption upon the occurrence of certain events, which are in the control of management. During fiscal year 1999, the Company repurchased 2,152 shares of Series C Preferred Stock at a cost of $2,251,000. During the years ended June 30, 1999 and 2000, 3,550 shares and 2,525 shares, respectively, of Series C Preferred Stock were converted into 1,328,639 shares and 8,217,831 shares, respectively, of Common Stock. Additionally, 77,571 shares and 914,712 shares of Common Stock, representing accrued but unpaid dividends due to the converting Series C Preferred Stock holders, were issued upon conversion during fiscal years 1999 and 2000, respectively. At June 30, 1998, 1999, and 2000, 10,400 shares, 4,698 shares, and 2,173 shares of Series C Preferred Stock were outstanding. Common Stock During July 1998, the Company completed the private placement of an aggregate of 3,428,574 shares of the Company's Common Stock at $7.00 per share (the July Equity Offerings) which included certain repricing rights (the Repricing Rights) to acquire additional shares of Common Stock (Repricing Common Shares) and warrants (the Warrants) to purchase an aggregate of up to 1,085,000 shares of Common Stock (Warrant Common Shares). Additionally, JEDI exercised warrants to acquire an aggregate of 980,935 shares of Common Stock at $3.33 per share and nondilution rights to purchase 693,301 shares of the Company's Common Stock at $2.50 per share and another entity exercised warrants F-18 94 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) to acquire an aggregate of 800,000 shares of Common Stock at $2.50 per share (collectively, the Warrant Exercises). During November 1998, the Company completed the private placement of an aggregate of 416,667 shares of the Company's Common Stock at $6.00 per share (the November Equity Offerings and, collectively with the July Equity Offerings, the Equity Offerings) which included certain repricing rights (the Repricing Rights) to acquire additional shares of Common Stock (Repricing Common Shares) and warrants (the Warrants) to purchase an aggregate of up to 206,340 shares of Common Stock (Warrant Common Shares). The Repricing Rights allow the purchasers of the Common Shares under the Equity Offerings to receive Repricing Common Shares based on the following formula: (Repricing Price - Market Price) -------------------------------- X Common Shares Market Price
The Repricing Price is a percentage increase in the purchase price paid for the Common Shares (up to 128% over the following eight months). The Repricing Rights can only be exercised one time and the Company can repurchase the Repricing Rights under certain conditions. During the years ended June 30, 1999 and 2000, 1,384,016 shares and 38,113,785 shares, respectively, of Common Stock were issued upon exercise of Repricing Rights. Each holder of Repricing Common Shares or Repricing Rights has the right to require the Company to repurchase all or a portion of such holder's Repricing Common Shares or Repricing Rights upon the occurrence of a Major Transaction or a Triggering Event, both of which are under the control of management of the Company. The Warrants are exercisable for three years commencing July 8, 1998 and November 23, 1998, at an exercise price equal to 110% of the Purchase Price. The Warrants provide for customary adjustments to the exercise price and number of shares to be issued in the event of certain dividends and distributions to holders of Common Stock, stock splits, combinations, and mergers. The Warrants also include customary provisions with respect to, among other things, transfer of the Warrants, mutilated or lost warrant certificates, and notices to holder(s) of the Warrants. Warrants Certain institutional investors hold warrants to purchase an aggregate of 1,525,153 shares of Common Stock at prices ranging from $6.00 to $8.00 per share. The warrants held by the institutional investors expire at various times from December 24, 2000 through November 25, 2001. F-19 95 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Stock Options Employee stock option activity for the years ended June 30, 1998, 1999, and 2000 is as follows:
YEAR ENDED JUNE 30, ------------------------------------------------------------ 1998 1999 2000 ------------------ ------------------ ------------------ WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE ------- -------- ------- -------- ------- -------- Outstanding at July 1....... -- $ -- 173,000 $5.25 763,500 $6.87 Granted................... 173,000 5.25 590,500 7.38 -- -- Exercised................. -- -- -- -- -- -- Canceled.................. -- -- -- -- (34,500) 7.38 ------- ------- ------- Outstanding at June 30...... 173,000 $5.25 763,500 $6.87 729,000 $6.84 ======= ======= ======= Exercisable options outstanding at June 30.... -- $ -- 96,500 $5.25 496,636 $6.67 ======= ======= =======
The weighted average grant date fair value of stock options granted during 1998 and 1999 were $3.22 and $6.23, respectively. The grant date fair values were estimated at the date of grant using the Black-Scholes option pricing model. As of June 30, 2000, the weighted average remaining contractual life of outstanding stock options was 7.3 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 5.88% and 6.00% during 1998 and 1999, respectively; a dividend yield of 0%; and a volatility factor of 0.51 and 0.792 during 1998 and 1999, respectively. In addition, the fair value of these options was estimated based on an expected weighted average life of 7.5 years and 10 years during 1998 and 1999, 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. 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 JUNE 30, ------------------------------------------ 1998 1999 2000 ------------ ------------ ------------ Pro forma net loss......................... $(32,928,000) $(48,917,000) $(10,106,000) Loss per common share...................... $ (1.45) $ (1.56) $ (0.23)
F-20 96 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 6. 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 June 30, 1999 and 2000, the carrying value of long-term obligations exceeded their fair values by approximately $41,250,000 and $76,875,000, respectively. At June 30, 1998, the carrying value of long-term obligations approximates their fair values. At June 30, 2000, the fair value of the Company's hedging contracts, measured as the estimated cost to the Company to terminate the arrangements, was approximately $5,256,000. 7. RELATED PARTY TRANSACTIONS The Company has entered into various hedging arrangements with affiliates of Enron (see Note 4). The Company had entered into a revolving credit facility with ECT, an affiliate of Enron. During the year ended June 30, 1998, commitment fees of approximately $200,000 and interest totaling approximately $9,000 was 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 years ended June 30, 1999 and 2000, Enron received interest payments of approximately $365,000 and $88,000, respectively, from the Company relating to such participation. The Company paid Enron approximately $100,000 during both of the years ended June 30, 1999 and 2000, under the terms of an agreement which allows the Company to consult, among other things, with Enron's engineering staff. 8. INCOME TAXES The Company's effective tax rate differs from the U.S. statutory rate for each of the years ended June 30, 1998, 1999, and 2000, 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 as determined under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, at June 30, 1999 and 2000, follow:
1999 2000 ------------ ------------ Deferred income tax assets (liabilities): Reverse acquisition costs.............................. $ 43,000 $ 21,000 Net operating loss carryforwards....................... 10,965,000 19,744,000 Statutory depletion carryforward....................... 126,000 126,000 Oil and gas properties, principally due to differences in depreciation and amortization.................... 16,902,000 11,109,000 Other.................................................. (146,000) (221,000) ------------ ------------ 27,890,000 30,779,000 Less valuation allowance................................. (27,890,000) (30,779,000) ------------ ------------ Net deferred income tax asset............................ $ -- $ -- ============ ============
The net changes in the total valuation allowance for the years ended June 30, 1999 and 2000, were increases of $15,677,000 and $2,889,000, respectively. The Company's net operating loss carryforwards begin expiring in 2010. F-21 97 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 9. 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. 10. 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 June 30, 1998, 1999, and 2000:
1998 1999 2000 ------------ ------------ ------------ Oil and gas sales.......................... $ 6,446,000 $ 4,591,000 $ 3,967,000 Net profits and royalty interests revenues................................. 4,432,000 23,140,000 22,990,000 Production expenses........................ (4,547,000) (3,196,000) (1,372,000) Depreciation and amortization.............. (4,736,000) (11,803,000) (8,452,000) Write-down of oil and gas properties....... (28,166,000) (35,033,000) -- ------------ ------------ ------------ Results of operations (excludes corporate overhead and interest expense)........... $(26,571,000) $(22,301,000) $ 17,133,000 ============ ============ ============
Depreciation and amortization of oil and gas properties was $0.89, $0.74, and $0.71 per Mcfe produced for the years ended June 30, 1998, 1999, and 2000, respectively. The following table summarizes capitalized costs relating to oil and gas producing activities and related amounts of accumulated depreciation and amortization at June 30, 1999 and 2000:
1999 2000 ------------ ------------ Oil and gas properties -- proved......................... $178,421,000 $182,280,000 Accumulated depreciation and amortization................ (81,469,000) (89,921,000) ------------ ------------ Net capitalized costs.................................... $ 96,952,000 $ 92,359,000 ============ ============
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 June 30, 1998, 1999, and 2000:
1998 1999 2000 ------------ ----------- ------------ Property acquisition costs.................. $153,196,000 $ 580,000 $ -- ============ =========== ============ Development costs........................... $ 6,031,000 $10,340,000 $ 6,198,000 ============ =========== ============
11. 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 F-22 98 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 June 30, 1997, 1998, and 1999, have been prepared by independent petroleum reservoir engineers. The estimate at June 30, 2000, has been prepared by the Company's petroleum engineers.
OIL (BBLS) GAS (MCF) ---------- ----------- Proved reserves: Balance at June 30, 1997.................................. 6,709,000 20,973,000 Purchases of minerals in place............................ 4,301,000 158,528,000 Revisions of previous estimates and other................. (2,736,000) (38,000) Production................................................ (325,000) (3,368,000) ---------- ----------- Balance at June 30, 1998.................................. 7,949,000 176,095,000 Sales of minerals in place................................ (2,735,000) (18,243,000) Revisions of previous estimates and other................. (90,000) (7,329,000) Production................................................ (500,000) (12,962,000) ---------- ----------- Balance at June 30, 1999.................................. 4,624,000 137,561,000 Sales of minerals in place................................ (1,000) (7,752,000) Revisions of previous estimates and other................. (2,389,000) 13,489,000 Production................................................ (224,000) (10,618,000) ---------- ----------- Balance at June 30, 2000.................................. 2,010,000 132,680,000 ========== =========== Proved developed reserves: Balance at June 30, 1997.................................. 2,188,000 12,412,000 ========== =========== Balance at June 30, 1998.................................. 5,298,000 120,998,000 ========== =========== Balance at June 30, 1999.................................. 2,138,000 94,614,000 ========== =========== Balance at June 30, 2000.................................. 1,868,000 86,348,000 ========== ===========
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. F-23 99 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Standardized Measure of discounted future net cash flows relating to proved oil and gas reserves as of June 30, 1999 and 2000, are as follows:
1999 2000 ------------- ------------- Future cash inflows.................................... $ 415,013,000 $ 653,511,000 Future costs and expenses: Production expenses.................................. (124,209,000) (171,740,000) Development costs.................................... (18,811,000) (14,735,000) Future income taxes.................................... (33,933,000) (95,642,000) ------------- ------------- Future net cash flows.................................. 238,060,000 371,394,000 10% annual discount for estimated timing of cash flows................................................ (123,642,000) (198,539,000) ------------- ------------- Standardized measure of discounted future net cash flows................................................ $ 114,418,000 $ 172,855,000 ============= =============
The weighted average price of oil and gas at June 30, 1999 and 2000, used in calculating the Standardized Measure were $17.11 and $31.42 per barrel, respectively, and $2.44 and $4.45 per MCF, respectively. Changes in the Standardized Measure of discounted future net cash flows relating to proved oil and gas reserves for the years ended June 30, 1998, 1999, and 2000, are as follows:
1998 1999 2000 ------------ ------------ ------------ Beginning balance.......................... $ 30,146,000 $142,315,000 $114,418,000 Purchases of minerals in place............. 139,292,000 -- -- Sales of minerals in place................. -- (16,035,000) (12,953,000) Developed during the period................ 6,031,000 10,340,000 6,198,000 Net change in prices and costs............. (15,593,000) 2,187,000 126,368,000 Revisions of previous estimates............ (13,784,000) (22,121,000) 13,225,000 Accretion of discount...................... 3,015,000 14,232,000 11,442,000 Net change in income taxes................. (461,000) 6,452,000 (61,709,000) Sales of oil and gas produced, net of production expenses...................... (6,331,000) (22,952,000) (24,134,000) ------------ ------------ ------------ Balance at June 30......................... $142,315,000 $114,418,000 $172,855,000 ============ ============ ============
The future cash flows shown above include amounts attributable to proved undeveloped reserves requiring approximately $12,930,000 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 gas and oil 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 gas and oil may differ materially from the amounts estimated. F-24 100 DEVX ENERGY, INC. (FORMERLY QUEEN SAND RESOURCES, INC.) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 12. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
THREE MONTHS ENDED ------------------------------------------------------- SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30 ------------ ------------ ----------- ----------- YEAR ENDED JUNE 30, 1999 Total revenues..................... $ 7,353,000 $ 6,984,000 $ 6,734,000 $ 6,986,000 Write-downs of oil and gas properties....................... -- $(35,033,000) -- -- Operating income................... $ 6,188,000 $ 6,295,000 $ 6,015,000 $ 6,363,000 Loss before extraordinary item..... $(2,104,000) $(37,678,000) $(1,977,000) $(2,183,000) Extraordinary loss................. $(3,549,000) -- -- -- Net loss........................... $(5,653,000) $(37,678,000) $(1,977,000) $(2,183,000) Loss before extraordinary item per common share..................... $ (0.07) $ (1.25) $ (0.06) $ (0.07) Net loss per common share.......... $ (0.19) $ (1.25) $ (0.06) $ (0.07)
THREE MONTHS ENDED ------------------------------------------------------- SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30 ------------ ------------ ----------- ----------- YEAR ENDED JUNE 30, 2000 Total revenues..................... $ 5,543,000 $ 6,653,000 $ 6,673,000 $ 8,231,000 Operating income................... $ 5,385,000 $ 6,533,000 $ 6,101,000 $ 7,709,000 Income (loss) before extraordinary item............................. $(2,242,000) $ (4,258,000) $(1,618,000) $ 190,000 Extraordinary loss................. $ -- $ (1,130,000) $ -- $ -- Net income (loss).................. $(2,242,000) $ (5,388,000) $(1,618,000) $ 190,000 Income (loss) before extraordinary item per common share............ $ (0.07) $ (0.12) $ (0.04) $ 0.00 Net income (loss) per common share............................ $ (0.07) $ (0.15) $ (0.04) $ 0.00
F-25 101 ------------------------------------------------------ ------------------------------------------------------ NO DEALER, SALESPERSON OR OTHER PERSON IS AUTHORIZED TO GIVE ANY INFORMATION OR TO REPRESENT ANYTHING NOT CONTAINED IN THIS PROSPECTUS. YOU MUST NOT RELY ON ANY UNAUTHORIZED INFORMATION OR REPRESENTATIONS. THIS PROSPECTUS IS AN OFFER TO SELL ONLY THE SHARES OFFERED HEREBY, BUT ONLY UNDER CIRCUMSTANCES AND IN JURISDICTIONS WHERE IT IS LAWFUL TO DO SO. THE INFORMATION CONTAINED IN THIS PROSPECTUS IS CURRENT ONLY AS OF ITS DATE. TABLE OF CONTENTS Summary................................. 3 Risk Factors............................ 10 Forward-Looking Statements.............. 18 The Recapitalization.................... 19 Price Range of Common Stock; Dividend History............................... 22 Use of Proceeds......................... 23 Capitalization.......................... 24 Dilution................................ 25 Selected Consolidated Financial Data.................................. 26 Unaudited Pro Forma Condensed Consolidated Financial Statements..... 28 Management's Discussion and Analysis of Financial Condition and Results of Operations............................ 33 Business................................ 44 Management.............................. 60 Security Ownership of Certain Beneficial Owners and Management................. 64 Description of Capital Stock............ 66 Shares Eligible for Future Sale......... 67 Underwriting............................ 68 Legal Matters........................... 69 Engineers............................... 70 Experts................................. 70 Where You Can Find More Information..... 70 Incorporation by Reference.............. 71 Glossary................................ 72 Index to Consolidated Financial Statements............................ F-1
------------------------------------------------------ ------------------------------------------------------ ------------------------------------------------------ ------------------------------------------------------ 10,000,000 SHARES COMMON STOCK DEVX ENERGY LOGO --------------------- PROSPECTUS --------------------- FRIEDMAN BILLINGS RAMSEY STIFEL, NICOLAUS & COMPANY, INCORPORATED ------------------------------------------------------ ------------------------------------------------------ 102 PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION. The expenses of this offering are estimated to be as follows: Securities and Exchange Commission registration fee..... $ 24,288 NASD filing fee......................................... 9,700 Nasdaq National Market fee.............................. 81,625 Legal fees and expenses................................. 125,000 Accounting fees and expenses............................ 275,000 Engineering fees and expenses........................... 5,000 Printing expenses....................................... 200,000 Transfer Agent fees..................................... 1,000 Other reimbursed underwriters' expenses (including legal and engineer fees and out-of-pocket expenses)......... 500,000 Miscellaneous........................................... 3,387 ---------- Total:........................................ $1,225,000 ==========
All of these expenses, except for the Securities and Exchange Commission registration fee, the Nasdaq National Market fee and the NASD filing fee, represent estimates only. We will pay all of the expenses of the offering. ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS. The Company's Restated Certificate of Incorporation, as amended (the "Certificate of Incorporation"), provides that no director of the Company will be personally liable to the Company or any of its stockholders for monetary damages arising from the director's breach of fiduciary duty as a director. However, this does not apply with respect to any action in which the director would be liable under Section 174 of the General Corporation Law of the State of Delaware ("Delaware Code") nor does it apply with respect to any liability in which the director (i) breached his duty of loyalty to the Company or its stockholders; (ii) did not act in good faith or, in failing to act, did not act in good faith; (iii) acted in a manner involving intentional misconduct or a knowing violation of law or, in failing to act, shall have acted in a manner involving intentional misconduct or a knowing violation of law; or (iv) derived an improper personal benefit. The Certificate of Incorporation of the Company provides that the Company shall indemnify its directors and officers and former directors and officers to the fullest extent permitted by the Delaware Code. Pursuant to the provisions of Section 145 of the Delaware Code, the Company has the power to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action, suit, or proceeding (other than an action by or in the right of the Company) by reason of the fact that he is or was a director, officer, employee, or agent of the Company, against any and all expenses, judgments, fines and amounts paid in settlement actually and reasonably incurred in connection with such action, suit, or proceeding. The power to indemnify applies only if such person acted in good faith and in a manner he reasonably believed to be in the best interest, or not opposed to the best interest, of the Company and with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The power to indemnify applies to actions brought by or in the right of the Company as well, but only to the extent of defense and settlement expenses and not to any satisfaction of a judgment or settlement of the claim itself and with the further limitation that in such actions no indemnification shall be made in the II-1 103 event of any adjudication of negligence or misconduct unless the court, in its discretion, believes that in light of all the circumstances indemnification should apply. The statute further specifically provides that the indemnification authorized thereby shall not be deemed exclusive of any other rights to which any such officer or director may be entitled under any bylaws, agreements, vote of stockholders or disinterested directors, or otherwise. In addition, we have entered into indemnification agreements with some of our directors. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling the Company pursuant to the foregoing provisions, the Company has been advised that in the opinion of the Commission such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. ITEM 16. EXHIBITS. (a) Exhibits:
1.1+ -- Form of Underwriting Agreement to be entered into among DevX Energy, Inc., Friedman, Billings, Ramsey & Co., Inc. and the other underwriters of this offering. 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 Amended and Restated Certificate of Incorporation of the Company. 3.4+ -- Form of Amendment to Restated Certificate of Incorporation of the Company. 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 -- Stockholders' Agreement dated as of May 6, 1997, among the Company, Bruce I. Benn, Edward J. Munden, Ronald I. Benn, Robert P. Lindsay, EIBOC Investments Ltd. and Joint Energy Development Investments Limited Partnership ("JEDI"), filed as an Exhibit to the Company's Current Report on Form 8-K dated May 6, 1997, which Exhibit is incorporated herein by reference. 4.2 -- 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. 4.3 -- Form of 12% Notes due July 15, 2001, filed as an Exhibit to the Company's Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on August 12, 1996, which Exhibit is incorporated herein by reference. 4.4 -- Form of Common Stock Purchase Warrant dated December 24, 1997 and issued to certain institutional investors, 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.
II-2 104
4.5 -- Form of Common Stock Purchase Warrant issued to certain investors effective July 8, 1998, 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. 4.6 -- Registration Rights Agreement among the Company and certain institutional investors named therein, dated December 24, 1997, 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. 4.7 -- Registration Rights Agreement by and between the Company and JEDI dated May 6, 1997, filed as an Exhibit to the Company's Current Report on Form 8-K dated May 6, 1997, which Exhibit is incorporated herein by reference. 4.8 -- Registration Rights Agreement dated as of July 8, 1998 among the Company and the buyers signatory thereto, 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. 4.9 -- Registration Rights Agreement dated November 10, 1998 among Queen Sand Resources, Inc. and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998, which Exhibit is incorporated herein by reference. 4.10 -- Form of Common Stock Purchase Warrant issued to certain investors as of November 10, 1998, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998, which Exhibit is incorporated herein by reference. 4.11 -- Form of Common Stock Purchase Warrant issued to Northern Tier Asset Management, Inc. issued by the Company on April 9, 1999 and filed as an exhibit to the Company's Registration Statement on form S-3 (No. 333-78001) which Exhibit is incorporated by reference. 4.12 -- Registration Rights Agreement dated as of April 9, 1999 between the Company and Northern Tier Asset Management, Inc. and filed as an exhibit to the Company's Registration Statement on form S-3 (No. 333-78001) which Exhibit is incorporated by reference. 4.13++ -- Settlement Agreement dated as of July 17, 2000 among the Company and the stockholders named therein. 4.14++ -- Participation Agreement dated as of July 17, 2000 among the Company and the holders of its 12 1/2% senior notes named therein. 4.15+ -- Amendment to Participation Agreement, dated October 4, 2000, among the Company and certain holders of its 12 1/2% senior notes named therein. 5.1+ -- Opinion of Haynes and Boone, LLP, regarding legality of the common stock issued. 10.1 -- Purchase and Sale Agreement between Eli Rebich and Southern Exploration Company, a Texas corporation, and Queen Sand Resources, Inc., a Nevada corporation, dated April 10, 1996, filed as an Exhibit to the Company's Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on August 12, 1996, which Exhibit is incorporated herein by reference. 10.2 -- Purchase and Sale Agreement dated March 19, 1998 among the Morgan commingled pension funds and Queen Sand Resources, Inc., a Nevada corporation, filed as an Exhibit to the Company's Current Report on Form 8-K dated March 19, 1998, which Exhibit is incorporated herein by reference.
II-3 105
10.3 -- Securities Purchase Agreement dated as of March 27, 1997 between JEDI and 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. 10.4 -- Securities Purchase Agreement among the Company and certain institutional investors named therein, dated December 22, 1997, 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. 10.5 -- 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. 10.6 -- 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. 10.7 -- 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. 10.8 -- 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. 10.9 -- Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Edward J. Munden, 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. 10.10 -- 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. 10.11 -- Amended and Restated Securities Purchase Agreement dated as of July 8, 1998 among the Company and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated July 8, 1998, as amended by the Current Report on Form 8-K/A-1 dated July 8, 1998, which Exhibit is incorporated herein by reference. 10.12 -- Securities Purchase Agreement dated as of November 10, 1998 among the Company and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998. 10.13 -- Amended and Restated Credit Agreement among the Company, Queen Sand Resources, Inc., a Nevada corporation, 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. 10.14 -- Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by Queen Sand 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.
II-4 106
10.15 -- Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by 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. 10.16 -- 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. 10.17 -- Security Agreement dated as of October 22, 1999, by and among the Company, Queen Sand Resources, Inc. (Nevada), 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. 10.18 -- Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by Queen Sand Resources, Inc., a Nevada corporation 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. 10.19 -- Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by Queen Sand Resources, Inc., a Delaware corporation, 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. 10.20++ -- Amendment No. 1 to Credit Agreement dated as of May 2000 among the Company, Queen Sand Resources, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto. 10.21++ -- Amendment No. 2 to Credit Agreement dated as of June 30, 2000 among the Company, Queen Sand Resources, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto. 10.22+ -- Employment Agreement dated September 22, 2000 between the Company and Joseph T. Williams. 10.23+ -- Release Agreement dated September 15, 2000 between the Company and Ronald I. Benn. 10.24+ -- Form of Indemnification Agreement for Directors. 23.1+ -- Consent of Ernst & Young LLP. 23.2+ -- Consent of Haynes and Boone, LLP (contained in legal opinion filed as Exhibit 5.1). 23.3+ -- Consent of Ryder Scott Company. 23.4+ -- Consent of H.J. Gruy and Associates, Inc. 24.1++ -- The power of attorney of officers and directors of the Company (found on signature page). 99.1+ -- Consent of Jerry B. Davis as Person about to become a Director. 99.2+ -- Consent of Robert L. Keiser as Person about to become a Director.
--------------- + Filed herewith. ++ Previously filed. II-5 107 (b) II Financial Statement Schedule and Auditors' Report on Schedule: No schedules filed No other financial statement schedules are filed as part of this Registration Statement 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. ITEM 17. UNDERTAKINGS. The undersigned registrant hereby undertakes that: (1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. (2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. II-6 108 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, the Company has duly caused this Pre-Effective Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, State of Texas, on the 6th day of October, 2000. DEVX ENERGY, INC., a Delaware corporation By: /s/ EDWARD J. MUNDEN ---------------------------------- Name: Edward J. Munden Title: Chief Executive Officer and President Pursuant to the requirements of the Securities Act of 1933, this Pre-Effective Amendment No. 1 to the Registration Statement on Form S-2 has been signed on the 6th day of October, 2000 by the following persons on behalf of the Registrant in the capacities and on the dates indicated:
SIGNATURE TITLE --------- ----- /s/ JOSEPH T. WILLIAMS Chairman of the Board and Director ----------------------------------------------------- Joseph T. Williams /s/ EDWARD J. MUNDEN* President, Chief Executive Officer and Director (principal ----------------------------------------------------- executive officer) Edward J. Munden /s/ BRUCE I. BENN* Executive Vice President, Secretary and Director ----------------------------------------------------- Bruce I. Benn /s/ WILLIAM W. LESIKAR Chief Financial Officer and Vice President (principal ----------------------------------------------------- financial officer and accounting officer) William W. Lesikar /s/ ROBERT P. LINDSAY* Chief Operating Officer, Executive Vice President and ----------------------------------------------------- Director Robert P. Lindsay
William W. Lesikar by signing his name hereto, does sign and execute this Pre-Effective Amendment No. 1 to the Registration Statement on behalf of each of the above-named officers and directors of the registrant on this 6th day of October 2000, pursuant to the powers of attorney executed on behalf of each of such officers and directors and previously filed with the Securities and Exchange Commission. *By: /s/ WILLIAM W. LESIKAR ----------------------------------- William W. Lesikar Attorney-in-Fact II-7 109 INDEX TO EXHIBITS
1.1+ -- Form of Underwriting Agreement to be entered into among DevX Energy, Inc., Friedman, Billings, Ramsey & Co., Inc. and the other underwriters of this offering. 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 Amended and Restated Certificate of Incorporation of the Company. 3.4+ -- Form of Amendment to Restated Certificate of Incorporation of the Company. 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 -- Stockholders' Agreement dated as of May 6, 1997, among the Company, Bruce I. Benn, Edward J. Munden, Ronald I. Benn, Robert P. Lindsay, EIBOC Investments Ltd. and Joint Energy Development Investments Limited Partnership ("JEDI"), filed as an Exhibit to the Company's Current Report on Form 8-K dated May 6, 1997, which Exhibit is incorporated herein by reference. 4.2 -- 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. 4.3 -- Form of 12% Notes due July 15, 2001, filed as an Exhibit to the Company's Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on August 12, 1996, which Exhibit is incorporated herein by reference. 4.4 -- Form of Common Stock Purchase Warrant dated December 24, 1997 and issued to certain institutional investors, 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. 4.5 -- Form of Common Stock Purchase Warrant issued to certain investors effective July 8, 1998, 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. 4.6 -- Registration Rights Agreement among the Company and certain institutional investors named therein, dated December 24, 1997, 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. 4.7 -- Registration Rights Agreement by and between the Company and JEDI dated May 6, 1997, filed as an Exhibit to the Company's Current Report on Form 8-K dated May 6, 1997, which Exhibit is incorporated herein by reference. 4.8 -- Registration Rights Agreement dated as of July 8, 1998 among the Company and the buyers signatory thereto, 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.
110
4.9 -- Registration Rights Agreement dated November 10, 1998 among Queen Sand Resources, Inc. and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998, which Exhibit is incorporated herein by reference. 4.10 -- Form of Common Stock Purchase Warrant issued to certain investors as of November 10, 1998, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998, which Exhibit is incorporated herein by reference. 4.11 -- Form of Common Stock Purchase Warrant issued to Northern Tier Asset Management, Inc. issued by the Company on April 9, 1999 and filed as an exhibit to the Company's Registration Statement on form S-3 (No. 333-78001) which Exhibit is incorporated by reference. 4.12 -- Registration Rights Agreement dated as of April 9, 1999 between the Company and Northern Tier Asset Management, Inc. and filed as an exhibit to the Company's Registration Statement on form S-3 (No. 333-78001) which Exhibit is incorporated by reference. 4.13++ -- Settlement Agreement dated as of July 17, 2000 among the Company and the stockholders named therein. 4.14++ -- Participation Agreement dated as of July 17, 2000 among the Company and the holders of its 12 1/2% senior notes named therein. 4.15+ -- Amendment to Participation Agreement, dated October 4, 2000, among the Company and certain holders of its 12 1/2% senior notes named therein. 5.1+ -- Opinion of Haynes and Boone, LLP, regarding legality of the common stock issued. 10.1 -- Purchase and Sale Agreement between Eli Rebich and Southern Exploration Company, a Texas corporation, and Queen Sand Resources, Inc., a Nevada corporation, dated April 10, 1996, filed as an Exhibit to the Company's Registration Statement on Form 10-SB filed with the Securities and Exchange Commission on August 12, 1996, which Exhibit is incorporated herein by reference. 10.2 -- Purchase and Sale Agreement dated March 19, 1998 among the Morgan commingled pension funds and Queen Sand Resources, Inc., a Nevada corporation, filed as an Exhibit to the Company's Current Report on Form 8-K dated March 19, 1998, which Exhibit is incorporated herein by reference. 10.3 -- Securities Purchase Agreement dated as of March 27, 1997 between JEDI and 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. 10.4 -- Securities Purchase Agreement among the Company and certain institutional investors named therein, dated December 22, 1997, 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. 10.5 -- 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. 10.6 -- 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.
111
10.7 -- 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. 10.8 -- 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. 10.9 -- Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Edward J. Munden, 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. 10.10 -- 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. 10.11 -- Amended and Restated Securities Purchase Agreement dated as of July 8, 1998 among the Company and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated July 8, 1998, as amended by the Current Report on Form 8-K/A-1 dated July 8, 1998, which Exhibit is incorporated herein by reference. 10.12 -- Securities Purchase Agreement dated as of November 10, 1998 among the Company and the buyers signatory thereto, filed as an Exhibit to the Company's Current Report on Form 8-K dated November 24, 1998. 10.13 -- Amended and Restated Credit Agreement among the Company, Queen Sand Resources, Inc., a Nevada corporation, 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. 10.14 -- Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by Queen Sand 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. 10.15 -- Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by 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. 10.16 -- 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. 10.17 -- Security Agreement dated as of October 22, 1999, by and among the Company, Queen Sand Resources, Inc. (Nevada), 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.
112
10.18 -- Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by Queen Sand Resources, Inc., a Nevada corporation 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. 10.19 -- Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by Queen Sand Resources, Inc., a Delaware corporation, 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. 10.20++ -- Amendment No. 1 to Credit Agreement dated as of May 2000 among the Company, Queen Sand Resources, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto. 10.21++ -- Amendment No. 2 to Credit Agreement dated as of June 30, 2000 among the Company, Queen Sand Resources, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto. 10.22+ -- Employment Agreement dated September 22, 2000 between the Company and Joseph T. Williams. 10.23+ -- Release Agreement dated September 15, 2000 between the Company and Ronald I. Benn. 10.24+ -- Form of Indemnification Agreement to be entered into among DevX Energy, Inc. and selected directors of DevX Energy, Inc. 10.25+ -- Amendment Number Three to Amended and Restated Credit Agreement, dated September , 2000, among Queen Sand Resources, Inc., a Delaware corporation, Queen Sand Resources, Inc., a Nevada corporation, Foothill Capital Corporation, as administrative agent for the lending group, Ableco Finance LLC, as collateral agent for the lending group, and each of the lenders signatory thereto. 23.1+ -- Consent of Ernst & Young LLP. 23.2+ -- Consent of Haynes and Boone, LLP (contained in legal opinion filed as Exhibit 5.1). 23.3+ -- Consent of Ryder Scott Company. 23.4+ -- Consent of H.J. Gruy and Associates, Inc. 24.1++ -- The power of attorney of officers and directors of the Company (found on signature page). 99.1+ -- Consent of Jerry B. Davis as Person about to become a Director. 99.2+ -- Consent of Robert L. Keiser as Person about to become a Director.
--------------- + Filed herewith. ++ Previously filed.