10-Q 1 d92111e10-q.txt FORM 10-Q FOR QUARTER ENDED SEPTEMBER 30, 2001 U.S. SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ---------- FORM 10-Q ---------- [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___ Commission File No. 0-21179 DEVX ENERGY, INC. DEVX ENERGY, INC. DEVX OPERATING COMPANY CORRIDA RESOURCES, INC. (Exact name of registrants as specified in their charter) DELAWARE 75-2615565 NEVADA 75-2564071 NEVADA 75-2593510 NEVADA 75-2691594 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification Nos.) 13760 NOEL ROAD, SUITE 1030 L.B. #44, DALLAS, TEXAS 75240-7336 (Address of principal executive offices)(Zip code) (972) 233-9906 (Registrants' telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of November 1, 2001: 12,649,522 PART I FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)

SEPTEMBER 30, DECEMBER 31, 2001 2000 -------------- -------------- ASSETS Current assets: Cash $ 11,168,000 $ 10,985,000 Other current assets 6,080,000 10,740,000 -------------- -------------- Total current assets 17,248,000 21,725,000 Net property and equipment 110,275,000 97,091,000 Other assets 5,215,000 4,174,000 -------------- -------------- $ 132,738,000 $ 122,990,000 ============== ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and other $ 10,697,000 $ 7,507,000 Derivatives -- 1,507,000 -------------- -------------- Total current liabilities 10,697,000 9,014,000 Long-term obligations, net of current portion 50,000,000 50,000,000 Derivatives 1,779,000 12,246,000 Commitments -- -- Stockholders' equity: Common stock, $0.234 par value, authorized 100,000,000 shares: Issued and outstanding 12,649,522 and 12,748,612 shares at September 30, 2001 and December 31, 2000, respectively 2,983,000 2,983,000 Additional paid-in capital 60,165,000 60,159,000 Treasury stock, at cost: 100,000 shares (525,000) -- Retained earnings 9,418,000 834,000 Accumulated other comprehensive loss (1,779,000) (12,246,000) -------------- -------------- Total stockholders' equity 70,262,000 51,730,000 -------------- -------------- Total liabilities and stockholders' equity $ 132,738,000 $ 122,990,000 ============== ==============

See accompanying notes to unaudited consolidated condensed financial statements. 1 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 ---------------------------- ---------------------------- 2001 2000 2001 2000 ------------ ------------ ------------ ------------ Revenues: Oil and gas sales $ 580,000 $ 1,317,000 $ 2,768,000 $ 3,501,000 Net profits and royalty interests 5,552,000 8,944,000 24,653,000 21,605,000 Interest and other income 118,000 15,000 377,000 74,000 ------------ ------------ ------------ ------------ Total revenues 6,250,000 10,276,000 27,798,000 25,180,000 ------------ ------------ ------------ ------------ Expenses: Oil and gas production expenses 162,000 464,000 1,160,000 1,558,000 Depreciation, depletion and amortization 2,424,000 2,074,000 7,087,000 6,354,000 General and administrative 2,051,000 924,000 4,139,000 2,475,000 Interest and financing expense 1,836,000 4,941,000 5,518,000 14,348,000 ------------ ------------ ------------ ------------ Total expenses 6,473,000 8,403,000 17,904,000 24,735,000 ------------ ------------ ------------ ------------ Operating income (loss) (223,000) 1,873,000 9,894,000 445,000 Change in fair value of derivatives 535,000 (496,000) 3,730,000 (496,000) ------------ ------------ ------------ ------------ Income (loss) before cumulative effect of accounting change 312,000 1,377,000 13,624,000 (51,000) Cumulative effect of accounting change, net of tax -- 413,000 -- 413,000 ------------ ------------ ------------ ------------ Income before income taxes 312,000 1,790,000 13,624,000 362,000 Income taxes (114,000) -- (5,040,000) -- ------------ ------------ ------------ ------------ Net income $ 198,000 $ 1,790,000 $ 8,584,000 $ 362,000 ============ ============ ============ ============ Earnings per common share: Basic $ 0.02 $ 3.46 $ 0.67 $ 0.91 ============ ============ ============ ============ Diluted $ 0.02 $ 1.08 $ 0.67 $ 0.34 ============ ============ ============ ============ Weighted average shares outstanding: Basic 12,744,274 517,237 12,747,150 397,034 ============ ============ ============ ============ Diluted 12,745,568 1,652,224 12,804,465 1,076,644 ============ ============ ============ ============

See accompanying notes to unaudited consolidated condensed financial statements. 2 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

NINE MONTHS ENDED SEPTEMBER 30 ---------------------------- 2001 2000 ------------ ------------ Cash flows from operating activities: Net income $ 8,584,000 $ 362,000 Depreciation, depletion and amortization 7,660,000 7,648,000 Cumulative effect of accounting change -- (413,000) Change in fair value of derivatives (3,730,000) 496,000 Net change in operating assets and liabilities 8,465,000 (8,710,000) ------------ ------------ Net cash provided by (used in) operating activities 20,979,000 (617,000) ------------ ------------ Cash flows used in investing activities: Additions to property and equipment (20,573,000) (8,324,000) Proceeds from sale of oil & gas properties 302,000 3,551,000 ------------ ------------ Net cash used in investing activities (20,271,000) (4,773,000) ------------ ------------ Cash flows from financing activities: Proceeds from long-term debt -- 4,894,000 Payments on long-term obligations -- (877,000) Purchase of treasury stock (525,000) -- ------------ ------------ Net cash provided by (used in) financing activities (525,000) 4,017,000 ------------ ------------ Net increase (decrease) in cash 183,000 (1,373,000) Cash at beginning of period 10,985,000 3,376,000 ------------ ------------ Cash at end of period $ 11,168,000 $ 2,003,000 ============ ============

See accompanying notes to unaudited consolidated condensed financial statements. 3 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS SEPTEMBER 30, 2001 (UNAUDITED) 1. BASIS OF PRESENTATION The accompanying consolidated financial statements include the accounts of DevX Energy, Inc. and its wholly owned subsidiaries (collectively, the "Company") after elimination of all significant intercompany balances and transactions. The financial statements have been prepared in conformity with generally accepted accounting principles which require management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. While management has based their assumptions and estimates on the facts and circumstances currently known, final amounts may differ from such estimates. The interim financial statements contained herein are unaudited but, in the opinion of management, include all adjustments (consisting only of normal recurring entries) necessary for a fair presentation of the financial position and results of operations of the Company for the periods presented. The results of operations for the three months and the nine months ended September 30, 2001 are not necessarily indicative of the operating results for the year ending December 31, 2001. Moreover, these financial statements do not purport to contain complete disclosure in conformity with generally accepted accounting principles and should be read in conjunction with the Company's Annual Report on Form 10-K for the transition period ended December 31, 2000. 2. DERIVATIVES The Company utilizes certain derivative financial instruments -- primarily swaps, floors and collars -- to reduce the risk of adverse changes in future oil and natural gas prices. Effective July 1, 2000, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), which requires the Company to recognize all derivatives on the balance sheet at fair value. The Company estimates fair value based on quotes obtained from the counter-parties to the derivative contracts. The Company recognizes the fair value of derivative contracts that expire in less than one year as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities. Derivatives that are not accounted for as hedges are adjusted to fair value through income. If the derivative is designated as a hedge, depending on the nature of the hedge, changes in fair value are either offset against the change in fair value of the hedged assets, liabilities or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. 4 The Company has designated a natural gas swap as a cash flow hedge. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings. Hedge effectiveness is measured quarterly based on the relative fair value between the derivative contract and the hedged item over time. During the three months ended September 30, 2001, the Company recognized a decrease in the derivative liability and an associated decrease in other comprehensive loss totaling approximately $2,405,000. During the nine months ended September 30, 2001, the Company recognized a decrease in the derivative liability and an associated decrease in other comprehensive loss totaling approximately $10,467,000. As of September 30, 2001, other current assets included $738,000 and other assets include $1,699,000 related to the fair value of derivative contracts. During the three and nine months ended September 30, 2001, the Company recognized non-cash gains of $535,000 and $3,730,000, respectively, in earnings related to the net change in fair value of derivative contracts which have not been designated as hedges. During the three months ended September 30, 2001, the Company received $464,000 and for the nine months ended September 30, 2001, the Company paid $3,428,000 in cash settlements on its natural gas hedges, which are included in net profits and royalty interests. 3. 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 three months ended September 30, 2001, the Company's comprehensive income differed from net income by approximately $2,405,000 related to the change in fair value of a natural gas swap contract designated as a hedge. For the three months ended September 30, 2000, the Company's comprehensive income differed from net income by $8,866,000. For the nine-month period ending September 30, 2001, the Company's comprehensive income differed from net income by approximately $10,467,000 related to the change in fair market value of a natural gas swap contract designated as a hedge. For the nine months ended September 30, 2000, the Company's comprehensive income differed from net income by $8,866,000. 5 4. EARNINGS PER SHARE The following table sets forth the computation of basic and diluted earnings per common share:

THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 --------------------------- --------------------------- 2001 2000 2001 2000 ------------ ------------ ------------ ------------ Numerator: Numerator for basic earnings per common share - net income $ 198,000 $ 1,790,000 $ 8,584,000 $ 362,000 ============ ============ ============ ============ Denominator: Denominator for basic earnings per common share - weighted average shares 12,744,274 517,237 12,747,150 397,034 Dilutive effect of stock options and warrants 1,294 -- 57,315 -- Dilutive effect of common stock repricing rights -- 1,134,987 -- 679,610 ------------ ------------ ------------ ------------ Denominator for diluted earnings per common share - adjusted weighted average shares 12,745,568 1,652,224 12,804,465 1,076,644 ============ ============ ============ ============ Earnings per common share Basic $ 0.02 $ 3.46 $ 0.67 $ 0.91 ============ ============ ============ ============ Diluted $ 0.02 $ 1.08 $ 0.67 $ 0.34 ============ ============ ============ ============

Weighted average common shares outstanding and losses per common share for the three and nine months ended September 30, 2000 have been restated for the effects of a 156-to-1 reverse stock split. 5. CEILING TEST WRITEDOWN Based on oil and natural gas prices in effect on September 30, 2001, a ceiling test writedown in the amount of $37.8 million would have been required to be charged against earnings. Due to the increases in natural gas prices subsequent to September 30, 2001, this writedown was not recorded. However, if prices decline to third quarter levels at year end, such an adjustment will be required. 6. SUBSEQUENT EVENT The Company announced on November 13, 2001 that it has entered into a definitive agreement which provides for a wholly owned subsidiary of Comstock Resources, Inc. to acquire the Company in a transaction in which DevX shareholders would receive $7.32 in cash per DevX share. The acquisition will be effected by a first step cash tender offer for all of the Company's outstanding common stock. The tender offer is expected to commence on November 15, 2001 and to remain open for at least 20 business days. The tender offer will be followed by a merger in which shareholders whose shares are not acquired in the tender offer will receive $7.32 per share in cash. The offer is conditioned on, 6 among other things, greater than 50% of the Company's outstanding shares being tendered. There is no assurance that a transaction will be completed. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING STATEMENTS We have made forward-looking statements in this document 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 document, 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. SELECTED FINANCIAL DATA The following tables set forth selected financial data for the Company, presented as if our net profits interests had been accounted for as working interests. The financial data were derived from the Consolidated Financial Statements of the Company and should be read in conjunction with the Consolidated Financial Statements and related Notes thereto included herein. The results of operations for the three months and the nine months ended September 30, 2001 will not necessarily be indicative of the operating results for the year ending December 31, 2001. 7

THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 ---------------------------- ---------------------------- 2001 2000 2001 2000 ------------ ------------ ------------ ------------ Oil and gas sales (1) $ 7,887,000 $ 11,394,000 $ 32,526,000 $ 28,898,000 Oil and gas production expenses (1) 1,917,000 1,597,000 6,265,000 5,350,000 General and administrative expenses 2,051,000 924,000 4,139,000 2,475,000 ------------ ------------ ------------ ------------ EBITDA (2) 3,919,000 8,873,000 22,122,000 21,073,000 Interest expense, excluding amortization of deferred charges (3) (1,661,000) (4,515,000) (4,945,000) (13,098,000) Depreciation, depletion and amortization (4) (2,599,000) (2,500,000) (7,660,000) (7,604,000) Interest and other income 118,000 15,000 377,000 74,000 Cumulative effect of accounting change -- 413,000 -- 413,000 Change in fair value of derivatives 535,000 (496,000) 3,730,000 (496,000) Income tax expense (114,000) -- (5,040,000) -- ------------ ------------ ------------ ------------ Net income from operations $ 198,000 $ 1,790,000 $ 8,584,000 $ 362,000 ============ ============ ============ ============

---------- (1) Oil and natural gas sales and production expenses related to net profits interests have been presented as if such net profits interests had been accounted for as working interests, net of cash settlements on hedges. (2) EBITDA represents earnings before interest expense, income taxes, depreciation, depletion and amortization expense, and excludes interest and other income, change in derivative fair value and cumulative effect of accounting change. 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 $175,000 and $426,000 of amortized deferred charges related to debt obligations for the three months ended September 30, 2001 and 2000, respectively. Depreciation, depletion and amortization includes $573,000 and $1,250,000 of amortized deferred charges related to debt obligations and $0 and $44,000 of amortized deferred charges related to the Company's natural gas price-hedging program for the nine months ended September 30, 2001 and 2000, respectively. 8

THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 --------------------------- --------------------------- 2001 2000 2001 2000 ------------ ------------ ------------ ------------ PRODUCTION VOLUMES: Natural gas (MMcf) 2,264 2,414 6,778 7,504 Oil (MBbls) 39 51 126 161 Total natural gas equivalent (MMcfe) 2,497 2,721 7,535 8,469 AVERAGE SALES PRICE: Natural gas ($/Mcf) $ 3.07 $ 4.10 $ 4.31 $ 3.25 Oil ($/Bbl) $ 25.09 $ 29.26 $ 26.45 $ 27.95 Natural gas equivalent (per Mcfe) $ 3.17 $ 4.19 $ 4.32 $ 3.41 SELECTED EXPENSES (PER MCFE): Lease operating expense $ 0.66 $ 0.44 $ 0.68 $ 0.49 Production taxes $ 0.12 $ 0.14 $ 0.16 $ 0.15 Depreciation, depletion and amortization of oil and natural gas properties $ 0.94 $ 0.76 $ 0.93 $ 0.74 General and administrative expenses $ 0.82 $ 0.34 $ 0.55 $ 0.29 Interest and financing charges $ 0.67 $ 1.66 $ 0.66 $ 1.55

The following discussion of the results of operations and financial condition should be read in conjunction with the Consolidated Condensed Financial Statements and related Notes thereto included herein. THE THREE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED TO THE THREE MONTHS ENDED SEPTEMBER 30, 2000 RESULTS OF OPERATIONS 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. REVENUES: Our total revenues decreased by $3.5 million, or 31%, to $7.9 million for the three months ended September 30, 2001 from $11.4 million during the comparable period in 2000. Natural gas contributed 88% of our total revenues for the September 2001 quarter and 87% during the September 2000 quarter. Our production of both oil and natural gas decreased for third quarter 2001 compared with third quarter 2000. Excessive leverage and depressed natural gas prices during 1999 and the first half of 2000 resulted in our curtailing capital spending and selling certain producing properties during those periods. Further, and for similar reasons, we have made no acquisitions of producing properties since April 1998. As a result, our production volumes have declined from third quarter 2000 levels. Improved natural gas prices 9 and completion of our recapitalization during the second half of 2000 have allowed us to increase our capital spending activity, beginning during the third quarter 2000. Approximately 35% of our 2001 capital expenditure program was used to develop our Kentucky property. This property was shut-in on June 4, 2001 due to market factors resulting in no production volumes being realized to date relating to this year's investment. A new market for this gas was established in November 2001. As a result of our drilling program in the Gilmer field, production from the field was 1 Bcf, up 25% from the 0.8 Bcf we produced during the third quarter 2000. We produced 39,000 barrels of crude oil during the three months ended September 30, 2001, a decrease of 12,000 barrels, or 24%, from the 51,000 barrels produced during the comparable period in 2000. The decrease in oil production is due to the Segno field not meeting production expectations as well as the divestment of our Caprock field effective July 1, 2001, and sale of certain properties in Martin County, Texas during the second quarter 2001. We produced 2.3 Bcf of natural gas during the three months ended September 30, 2001, a decrease of 150 MMcf, or 6%, from the 2.4 Bcf produced during the comparable period in 2000. The production during the third quarter of 2001 was impacted by decreases due to natural decline and shut-in of wells in Kentucky, offset by increased production in our Gilmer field due to the completion of new wells. Production in the New Albany Shale Gas field in Kentucky was curtailed in the first half of this year due to a partial plant shutdown of the industrial market that was purchasing our production. We were building additional gathering lines to service existing and future wells when sales to this market were permanently discontinued in June 2001. Our development activity in the field is ongoing. We are currently completing the 50 wells drilled in Phase IV of the project and will be connecting these wells to the gathering system as the wells are completed, bringing the total gas wells in this field to 109. On a thousand cubic feet of natural gas equivalent ("Mcfe") basis, production for the three months ended September 30, 2001 was 2.5 Bcfe, down 0.2 Bcfe, or 8%, from the 2.7 Bcfe produced during the comparable period in 2000. Production from properties that we owned during both periods was down 153 MMcfe, or 6%, during the three months ended September 30, 2001 when compared to production during the three months ended September 30, 2000. The decrease in revenue is due to a significant industry-wide decrease in natural gas prices. The average price per Mcf of natural gas sold by us was $3.07 during the three months ended September 30, 2001, a decrease of $1.03 per Mcf, or 25%, below the $4.10 per Mcf realized during the comparable period in 2000. The average price per barrel of crude oil sold by us during the three months ended September 30, 2001 was $25.09, a decrease of $4.17 per barrel, or 14%, below the $29.26 per barrel realized during the 10 three months ended September 30, 2000. On a Mcfe basis, the average price received by us during the three months ended September 30, 2001 was $3.17, a $1.02 decrease, or 24%, below the $4.19 we received during the comparable period in 2000. During the three months ended September 30, 2001, we received $464,000 in cash settlements under our natural gas price-hedging program. The net positive effect on the average natural gas prices we received during the period was $0.21 per Mcf. During the comparable period in 2000, we paid $1,050,000 in cash settlements under our natural gas price-hedging program. The net negative effect on the average natural gas prices we received during the 2000 period was $0.44 per Mcf. During the three months ended September 30, 2001, no crude oil price-hedging contracts were in place. During the comparable period in 2000, we paid $44,000 in cash settlements pursuant to our crude oil price-hedging program. SEVERANCE AND PRODUCTION TAXES: Severance and production taxes, which are based on the revenues derived from the sale of crude oil and natural gas, were $293,000 during the three months ended September 30, 2001 compared to $391,000 during the comparable period in 2000. This decrease of $98,000, or 25%, is primarily the result of lower revenues due to lower prices and volumes as well as the receipt of rebates in the Gilmer field. On a cost per Mcfe basis, severance taxes were $0.12 per Mcfe for the three months ended September 30, 2001 compared to $0.14 per Mcfe for the comparable period ending September 30, 2000, a decrease of 14%. PRODUCTION EXPENSES: Our lease operating expenses increased to $1.7 million for the three months ended September 30, 2001, an increase of $0.5 million, or 42%, from the $1.2 million incurred during the comparable period in 2000. This is due to higher ad valorem taxes, increased chemical and treating costs, and higher gathering charges relating to increased production in the Gilmer field incurred in this period compared to the comparable period in 2000. Lease operating expenses were $0.66 per Mcfe during the three months ended September 30, 2001, an increase of $0.22, or 50%, from the $0.44 per Mcfe incurred during the comparable period in 2000. The increase in average costs per unit is a result of the higher costs mentioned above combined with lower production volumes. DEPLETION, DEPRECIATION AND AMORTIZATION EXPENSE: Depletion and oil field equipment related depreciation costs were $2.4 million for the three months ended September 30, 2001, an increase of 14% over the $2.1 million for the comparable period in 2000. On a Mcfe basis, depletion and oil field equipment related depreciation was $0.94 per Mcfe during the three months, an increase of $0.18 per Mcfe, or 24%, from the $0.76 per Mcfe during the comparable period in 2000. The increase, on a cost per Mcfe basis, is primarily due to capitalized costs increasing at a faster rate than the reserve base. 11 GENERAL AND ADMINISTRATIVE EXPENSES: The increase of $1.1 million, or 122%, in general and administrative costs for the three months ended September 30, 2001 is primarily a result of costs related to the closing of our Ottawa office. These costs include severance payments to the former president and to the general counsel and for costs relating to the payoff of the office lease. INTEREST EXPENSE: Interest expense decreased by $3.1 million to $1.8 million for the three months ended September 30, 2001 compared to $4.9 million for the three months ended September 30, 2000. The interest expense of $1.8 million is comprised of $1.6 million in cash interest charges and $0.2 million of amortized deferred debt issuance costs. The decrease in interest expense resulted from the repurchase during 2000 of $75.0 million of our senior notes and reduction in other long-term debt of $14.0 million. During the three months ended September 30, 2000, there were $0.4 million of amortized deferred debt issuance costs included in the interest expense of $4.9 million. CHANGE IN DERIVATIVE FAIR VALUE: During the quarter ended September 30, 2001, we recorded a gain of $0.5 million representing the change in fair value of our derivative contracts that are not accounted for as hedges. During the three months ended September 30, 2000, we recorded a loss of $0.5 million representing the change in fair value of our derivatives contracts that are not accounted for as hedges. NET INCOME: For the three months ended September 30, 2001, we recorded net income of $0.2 million or $0.02 per basic and diluted share, compared to income of $1.8 million or $3.46 per basic and $1.08 per diluted share for 2000. Decreased natural gas prices and increased general and administrative costs are the primary causes of the decline. THE NINE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED TO THE NINE MONTHS ENDED SEPTEMBER 30, 2000 RESULTS OF OPERATIONS 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. REVENUES: Our total revenues increased by $3.6 million, or 13%, to $32.5 million for the nine months ended September 30, 2001 from $28.9 million during the comparable period in 2000. Natural gas contributed 90% of our total revenues for the nine months ended September 2001 and 84% during the comparable period in 2000. 12 Our production of both oil and natural gas decreased for the nine months ended September 30, 2001 compared with the nine months ended September 30, 2000. Excessive leverage and depressed natural gas prices during 1999 and the first half of 2000 resulted in our curtailing capital spending and selling certain producing properties during those periods. Further, and for similar reasons, we have made no acquisitions of producing properties since April 1998. As a result, our production volumes have declined for the nine months ended September 30, 2001 compared with the same period in 2000. Improved natural gas prices and completion of our recapitalization during the second half of 2000 have allowed us to increase our capital spending activity, beginning during the third quarter 2000. Approximately 35% of our 2001 capital expenditure program was used to develop our Kentucky property. This property was shut-in on June 4, 2001 due to market factors resulting in no production volumes being realized to date relating to this year's investment. A new market for this gas was established in November 2001. As a result of our drilling program in the Gilmer field, production from this field was 2.8 Bcf, up 27% from the 2.2 Bcf produced during the nine months ended September 30, 2000. We produced 126,000 barrels of crude oil during the nine months ended September 30, 2001, a decrease of 35,000 barrels, or 22%, from the 161,000 barrels produced during the comparable period in 2000. This production decrease is primarily a result of lower than expected performance in our Segno field as well as the divestment of our Caprock field effective July 1, 2001, and sale of certain properties in Martin County, Texas in the second quarter 2001. We produced 6.8 Bcf of natural gas during the nine months ended September 30, 2001, a decrease of 726 MMcf, or 10%, from the 7.5 Bcf produced during the comparable period in 2000. This decrease consists of a decrease of 583 MMcf, or 8%, from the properties that we owned during both periods and a decrease of 143 MMcf from the properties that we sold at the end of June 2000 and in the first half of 2001. Production during the first nine months of 2001 was impacted by decreases due to natural decline and shut-in of wells in Kentucky offset by increased production in the Gilmer field due to completion of new wells. Production in the New Albany Shale Gas field in Kentucky was curtailed in the first half of this year due to a partial plant shutdown of the industrial market that was purchasing our production. We were building additional gathering lines to service existing and future wells when sales to this market were permanently discontinued in June 2001. Our development activity in the field is ongoing. We are currently completing the 50 wells drilled in Phase IV of the project and will be connecting these wells to the gathering system as the wells are completed, bringing the total gas wells in this field to 109. On a thousand cubic feet of natural gas equivalent ("Mcfe") basis, production for the nine months ended September 30, 2001 was 7.5 Bcfe, down 0.9 Bcfe, or 11%, from the 8.4 Bcfe produced during the comparable period in 2000. Production from properties that we owned during both periods was down 13 708 MMcfe, or 9%, during the nine months ended September 30, 2001 when compared to production during the nine months ended September 30, 2000. The increase in revenues was due to a significant, industry-wide increase in natural gas prices which peaked during the first half of this year. Prices have since come down to levels not seen since the first quarter of 2000. The effect of the increased gas prices was partially offset by lower production volume and slightly lower oil prices. The average price per barrel of crude oil sold by us during the nine months ended September 30, 2001 was $26.45, a decrease of $1.50 per barrel, or 5%, below the $27.95 per barrel during the nine months ended September 30, 2000. The average price per Mcf of natural gas sold by us was $4.31 during the nine months ended September 30, 2001, an increase of $1.06 per Mcf, or 33%, over the $3.25 per Mcf realized during the comparable period in 2000. During the nine months ended September 30, 2001, we paid $3,428,000 in cash settlements under our natural gas price-hedging program. The net negative effect on the average natural gas prices we received during the period was $0.50 per Mcf. During the comparable period in 2000, we paid $1,666,000 and amortized $44,000 of deferred hedging costs regarding our natural gas price-hedging program. The net negative effect on the average natural gas prices we received during the 2000 period was $0.22 per Mcf. During the nine months ended September 30, 2001, no crude oil price hedging contracts were in place. During the comparable period in 2000, we paid $153,000 in cash settlements pursuant to our crude oil price-hedging program. SEVERANCE AND PRODUCTION TAXES: Severance and production taxes, which are based on the revenues derived from the sale of crude oil and natural gas, were $1,174,000 during the nine months ended September 30, 2001 compared to $1,238,000 during the comparable period in 2000. This decrease of $64,000, or 5%, is primarily the result of severance tax rebates on our Gilmer and J.C. Martin fields received during the first nine months of 2001 offset by increased taxes due to increased revenues. On a cost per Mcfe basis, severance taxes were $0.16 per Mcfe for the nine months ended September 30, 2001 compared to $0.15 per Mcfe for the comparable period ending September 30, 2000, an increase of 7%. This increase is a result of lower volumes offset by lower severance taxes due to rebates received in this period. PRODUCTION EXPENSES: Our lease operating expenses increased to $5.1 million for the nine months ended September 30, 2001, an increase of $1.0 million, or 24%, from the $4.1 million incurred during the comparable period in 2000. The nine-month period ending September 30, 2001 included increased ad valorem taxes, chemical and treating costs, and gathering charges resulting from higher production volumes in the Gilmer field when compared to the comparable period in 2000. Lease operating expenses were $0.68 14 per Mcfe during the nine months ended September 30, 2001, an increase of $0.19, or 39%, from the $0.49 per Mcfe incurred during the comparable period in 2000. The increase in average costs per unit is a result of increased total costs and lower production volumes. DEPLETION, DEPRECIATION AND AMORTIZATION EXPENSE: Depletion and oil field equipment related depreciation costs were $7.0 million for the nine months ended September 30, 2001, an increase of 11% over the $6.3 million for the comparable period in 2000. On a Mcfe basis, depletion and oil field equipment related depreciation was $0.93 per Mcfe during the nine months, an increase of $0.19 per Mcfe, or 26%, from the $0.74 Mcfe per during the comparable period in 2000. The increase, on a cost per Mcfe basis, is primarily due to capitalized costs increasing at a faster rate than the reserve base. GENERAL AND ADMINISTRATIVE EXPENSES: The increase of $1.7 million, or 67%, in general and administrative costs for the nine months ending September 30, 2001 is primarily a result of costs incurred relating to the closing of our Ottawa office as well as increased audit fees and engineering costs. INTEREST EXPENSE: Interest expense decreased by $8.8 million to $5.5 million for the nine months ended September 30, 2001 compared to $14.3 million for the nine months ended September 30, 2000. The interest expense of $5.5 million is comprised of $4.9 million in cash interest charges and $0.6 million of amortized deferred debt issuance costs. The decrease in interest expense resulted from the repurchase of $75.0 million of our senior notes and reduction in other long-term debt of $14.0 million. During the nine months ended September 30, 2000, there were $1.3 million of amortized deferred debt issuance costs included in the interest expense of $14.3 million. CHANGE IN DERIVATIVE FAIR VALUE: During the nine months ended September 30, 2001, we recorded a gain of $3.7 million representing the change in fair value of our derivative contracts that are not accounted for as hedges. During the comparable period in 2000, we recorded a loss of $0.5 million representing the change in fair value of our derivative contracts that are not accounted for as hedges. NET INCOME: For the nine months ended September 30, 2001, we recorded net income of $8.6 million or $0.67 per basic and diluted share, compared to net income of $0.4 million or $0.91 and $0.34 per basic and diluted share, respectively, for 2000. The reduction of debt and increased natural gas prices are the primary causes of the significantly improved results. 15 LIQUIDITY AND CAPITAL RESOURCES GENERAL During the year ended December 31, 1999 and the first half of 2000, our acquisition and development spending were significantly curtailed as a result of the combined impact of depressed natural gas prices and excessive leverage. We also sold producing properties during those periods. As a result of reduced spending combined with property sales, our production rates have been declining. During 1999, we invested $7.5 million in development activities and sold producing properties for proceeds of $10.2 million. During the first half of 2000, we invested $4.0 million in development of our properties and sold producing properties for proceeds of $3.4 million. Increasing natural gas prices during the last half of 2000 and completion of our recapitalization during October 2000 enabled us to increase our capital spending activities. During the last half of 2000, we spent $9.1 million in capital activities. As planned, our capital spending level has continued to grow as we invested $20.6 million during the first nine months of 2001, including $3.1 million in exploration activities. Our plans for the remainder of 2001 call for additional capital spending of approximately $10 million, of which, approximately 20% is allocated to exploration activities. The increased spending levels are intended to increase our reserves and production rates. We have already seen production increases in the Gilmer field due to our accelerated drilling program, and we expect to see increased production in our Kentucky properties as wells are placed on production during November 2001. We have planned development and exploitation activities for all of our major operating areas. We plan to spend a total of approximately $30 million in capital activities during 2001. During the nine months ended September 30, 2001, we have spent $20.6 million and have a further $14.2 million contractually committed, some of which will occur during 2002. Of the total planned capital expenditures for the year, approximately 17% is allocated to exploration activities. We believe our existing cash balances and cash flow from operations combined with our existing credit facility will be sufficient to fund our planned exploration, development and exploitation activities for 2001. In addition, we are continuing to evaluate oil and natural gas properties for future acquisition. Historically, we have used the proceeds from the sale of our securities in the private equity market and borrowings under our credit facilities to raise cash to fund acquisitions or repay indebtedness incurred for acquisitions. We have also used our securities as a medium of exchange for other companies' assets in connection with acquisitions. However, there can be no assurance that such sources will be available to us to meet our budgeted capital spending. Furthermore, our ability to borrow other than under the amended and restated credit agreement with Ableco Finance LLP and Foothill Capital Corporation is subject to restrictions imposed by our credit agreement and the indenture governing our senior notes. If we cannot secure additional funds for our planned development and exploitation activities, then we will be required to delay or reduce substantially our development and exploitation efforts. 16 Total current assets decreased by $4.5 million from December 31, 2000 to September 30, 2001 as oil and gas sales receivable fell as a result of lower natural gas prices. Part of the Company's strategy to increase shareholder value is to actively seek corporate acquisitions and mergers. On April 24, 2001, we announced that we had received written indications of interest that could result in the merger or sale of the Company. At the same time, we announced that we had instructed our investment bankers to evaluate those expressions of interest as well as other merger or sale alternatives. On November 13, 2001, we announced that we entered into a definitive agreement which provides for a wholly owned subsidiary of Comstock Resources, Inc. to acquire DevX in a transaction in which DevX shareholders would receive $7.32 in cash per DevX share. The acquisition will be effected by a first step cash tender offer for all of DevX's outstanding common stock. The tender offer is expected to commence on November 15, 2001 and to remain open for at least 20 business days. The tender offer will be followed by a merger in which shareholders whose shares are not acquired in the tender offer will receive $7.32 per share in cash. The offer is conditioned on, among other things, greater than 50% of the outstanding DevX shares being tendered. There is no assurance that a transaction will be completed. SOURCES OF CAPITAL We have a credit agreement with Ableco Finance LLC and Foothill Capital Corporation which allows for borrowings up to $50 million, subject to borrowing base limitations, from such lenders to fund, among other things, development and exploitation expenditures, acquisitions and general working capital. Our borrowing base under the credit agreement is currently $43.5 million. As of November 1, 2001, under this facility, we had no indebtedness outstanding, had $0.1 million reserved to secure a letter of credit, and were permitted to borrow an additional $43.4 million. Under the credit agreement, we have provided a first lien on all of our assets to secure our obligations under the agreement. The credit agreement matures on April 22, 2003. There are no scheduled principal repayments. The credit agreement bears interest as follows: o When the borrowings are less than $30 million or borrowings are less than 67% of the borrowing base as defined in the agreement, bank prime plus 2%; o When the borrowings are $30 million or greater and borrowings exceed 67% of the borrowing base as defined in the agreement, bank prime plus 3.5%; 17 o On amounts securing letters of credit issued on our behalf, 3%. The credit agreement contains certain affirmative and negative financial covenants, including maintaining interest coverage ratio greater than 1, a minimum of 1.5-to-1 working capital ratio (calculated as set out in the credit agreement) and a $30 million annual limit on capital spending. The Company has been in compliance with all covenants during the nine months ended September 30, 2001. We have a letter of credit outstanding under the credit agreement in the amount of $0.1 million, as of November 1, 2001, to secure a swap exposure. The letter of credit has the effect of reducing our credit availability under the credit agreement. Effective as of August 31, 2001 we issued warrants to purchase a total of 265,000 shares of our common stock to two former employees as part of their severance packages [see Part II, Item 5 - Other Information]. The warrants carry an exercise price of $7.00 per share. The warrants become exercisable in stages over the period ending October 27, 2002 and all of them become exercisable immediately in the event of a change of control of the Company. The warrants expire in February and March 2003. 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 April 1998, our primary method of replacing production and enhancing our reserves has been through the development and exploitation of our oil and natural gas properties. We have recently entered into two exploration joint ventures and expect to allocate approximately 17% of our 2001 capital spending to exploration activities. We expect to spend approximately $30 million on capital spending during 2001 for exploitation, development and exploration projects. As of September 30, 2001, we are contractually obligated to fund a further $14.2 million in capital expenditures, some of which will occur during 2002. We believe that cash on hand, cash flow from operations and our credit agreement will be sufficient to fund our planned activities. However, our cash flow from operations is significantly affected by the uncertainty of commodity prices. If there were a significant, protracted decline in prices, we would evaluate our projects and may delay or defer some of our planned activities. During the nine months ended September 30, 2001, we recorded $20.6 million in capital expenditures. Of this amount, $3.1 million relate to exploration activities with the balance of $17.5 million used in property development. 18 On September 4, 2001, we announced a stock buy back program of up to one million shares of our outstanding common stock. The program will be available over a period of approximately 16 months ending on December 31, 2002. The Company expects to fund the repurchase program from cash on hand. The repurchase program is being implemented on the open market or in privately negotiated transactions from time to time. Repurchases of stock will occur at management's discretion, depending upon price and availability. In the quarter ending September 30, 2001, we repurchased a total of 100,000 shares of common stock in the open market at an average price of $5.25 per share. All shares repurchased under this program will be held as treasury shares, which may be used to satisfy our current and near term requirements under our equity incentive and other benefit plans and for other corporate purposes. This program was suspended in conjunction with the Company's discussions with Comstock and will remain suspended during the pendency of the tender offer contemplated in the Company's agreement with Comstock. HEDGING ARRANGEMENTS, LETTERS OF CREDIT AND INSURANCE 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. Our credit agreement permits up to $12 million in letters of credit. As of November 1, 2001, we have provided $0.1 million in letters of credit related to our hedge contracts containing "caps." OTHER CONTINGENCIES On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scope. On October 7, 2001, the United States commenced military action in Afghanistan in response to these attacks. These developments have caused instability in the world's financial and insurance markets. In addition, these developments could lead to increased volatility in prices for crude oil and natural gas. Insurance premiums charged for some or all of the coverages the Company has historically maintained could increase materially, or the coverages could be unavailable in the future. These developments could have an adverse effect on our business and on our share price. 19 INFLATION Although inflation has not had a significant impact on our results of operations during the past several years, oil and gas production and development costs, lease acquisition and operating costs, labor availability, drilling costs (including costs of pipe, drill fluids and rig crews) and availability of rigs, fluctuate in response to overall industry conditions and demand for leases and rigs. Moreover, the prices we receive for our production fluctuate upward and downward, often significantly and often in a short period of time. This can and will affect our revenues from quarter to quarter. CHANGES IN PRICES AND HEDGING ACTIVITIES Annual average oil and natural gas prices have fluctuated significantly over the last two years. The table below sets out our weighted average price per barrel of oil and the weighted average price per Mcf of natural gas, the impact of our hedging programs and the related NYMEX indices.

THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 ------------------------ ------------------------ 2001 2000 2001 2000 ---------- ---------- ---------- ---------- GAS (PER Mcf) Price received at wellhead $ 2.86 $ 4.54 $ 4.81 $ 3.47 Effect of hedge contracts $ 0.21 $ (0.44) $ (0.50) $ (0.22) Effective price received including hedge contracts $ 3.07 $ 4.10 $ 4.31 $ 3.25 Average NYMEX Henry Hub $ 2.98 $ 4.31 $ 5.00 $ 3.41 Average basis differential including hedge contracts $ 0.09 $ (0.21) $ (0.69) $ (0.16) Average basis differential excluding hedge contracts $ (0.12) $ 0.23 $ (0.19) $ 0.06 OIL (PER BARREL) Price received at wellhead $ 25.09 $ 30.12 $ 26.45 $ 28.90 Effect of hedge contracts $ 0.00 $ (0.86) $ 0.00 $ (0.95) Effective price received including hedge contracts $ 25.09 $ 29.26 $ 26.45 $ 27.95 Average NYMEX Sweet Light Oil $ 26.50 $ 31.57 $ 27.72 $ 30.20 Average basis differential including hedge contracts $ (1.41) $ (2.31) $ (1.27) $ (2.25) Average basis differential excluding hedge contracts $ (1.41) $ (1.45) $ (1.27) $ (1.30)

We have a commodity price risk management or hedging strategy that is designed to provide protection from low commodity prices while providing some opportunity to enjoy the benefits of higher commodity prices. We have a series of natural gas futures contracts with various counter-parties. This strategy is designed to provide a degree of protection from negative shifts in natural gas prices as reported on the 20 Henry Hub Nymex Index. For the year ending December 31, 2001, we have 8.7 Bcf hedged at a weighted average floor price of $3.00/Mcf and 5.0 Bcf hedged with a weighted average ceiling price of $5.38/Mcf. For the six months ending December 31, 2001, we have 4.1 Bcf hedged at a weighted average floor price of $2.76 Mcf and 2.3 Bcf hedged with a weighted average ceiling price of $4.84/Mcf. The table below sets out the volume of natural gas that remains under contract with the Bank of Montreal at a floor price of $2.00 per MMBtu. The volumes set out in this table are divided equally over the months during the period:

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

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, 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, 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

At current natural gas price levels, we have a net liability to Enron related to our hedge positions in which Enron is the counter-party. If natural gas futures prices fall below $2.40 per MMBtu in the future, our hedge positions with Enron would become a net asset, and we would have credit exposure to Enron to that extent. We will continue to monitor our potential exposure with Enron. 21 The table below sets out the volume of natural gas and floor and ceiling prices hedged with Texaco. The volumes presented in this table are divided equally over the months during the period:

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Changes in Prices and Hedging Activities." 22 PART II OTHER INFORMATION ITEM 5. OTHER INFORMATION On February 13, 2001, we announced the implementation of a four-part strategy directed at growing our asset base and increasing shareholder value. This strategy consists of: (1) establishing an exploration program to add reserves at competitive finding costs; (2) developing and exploiting our existing properties; (3) pursuing selective property acquisitions; and (4) actively seeking corporate acquisitions and mergers. On April 24, 2001, we announced that we had received written indications of interest that could result in the merger or sale of the company for cash or a combination of cash and stock. At the same time, we announced that we had instructed our investment bankers to evaluate the expressions of interest as well as other merger or sale alternatives to maximize stockholder value. On November 13, 2001, we announced that we entered into a definitive agreement which provides for a wholly owned subsidiary of Comstock Resources, Inc. to acquire DevX in a transaction in which DevX shareholders would receive $7.32 in cash per DevX share. The acquisition will be effected by a first step cash tender offer for all of DevX's outstanding common stock. The tender offer is expected to commence on November 15, 2001 and to remain open for at least 20 business days. The tender offer will be followed by a merger in which shareholders whose shares are not acquired in the tender offer will receive $7.32 per share in cash. The offer is conditioned on, among other things, greater than 50% of the outstanding DevX shares being tendered. There is no assurance that a transaction will be completed. On September 4, 2001, we announced a stock buy back program of up to 1 million shares of our outstanding common stock. The program will be available over a period of approximately 16 months ending on December 31, 2002. The Company expects to fund the repurchase program from cash on hand. The repurchase program is being implemented on the open market or in privately negotiated transactions from time to time. Repurchases of stock will occur at management's discretion, depending upon price and availability. In the quarter ending September 30, 2001, we repurchased a total of 100,000 shares of common stock in the open market at an average price of $5.25 per share. All shares repurchased under this program will be held as treasury shares, which may be used to satisfy our current and near term requirements under our equity incentive and other benefit plans and for other corporate purposes. This program was suspended in conjunction with the Company's discussions with Comstock and will remain suspended during the pendency of the tender offer contemplated in the Company's agreement with Comstock. 23 On August 6, 2000, in connection with the Company's decision to close our offices in Ottawa, Canada, the Board notified Mr. Munden that it required him to relocate to Dallas on or before November 6, 2001. Mr. Munden declined to relocate and instead elected to resign effective on August 31, 2001. As a settlement of its obligations under Mr. Munden's employment contract, which was to have expired on November 10, 2002, the Company entered into a termination severance agreement with Mr. Munden under which it agreed to pay him $579,853 consisting of his Base Salary plus accrued Highest Annual Bonus through November 6, 2001 plus a severance payment equal to the sum of one year's Base Salary plus his Highest Annual Bonus (as those capitalized terms were defined in his employment contract) in exchange for a non-competition and non-solicitation agreement from Mr. Munden and his general release and surrender of his options. The termination agreement also provides that we will issue 240,000 warrants to Mr. Munden to replace the options that he had been previously granted. The warrants have an exercise price of $7.00 per share and will expire on September 27, 2003. In the event that a Change of Control (as defined in Mr. Munden's employment contract) occurs at any time through March 31, 2003, the Company will pay Mr. Munden an additional amount of two times his Base Salary and Highest Annual Bonus (the Comstock transaction will constitute a change of control). As part of the severance package, the Company also agreed to pay Mr. Munden an additional cash amount of $36,086 in consideration of its obligation to maintain certain fringe benefits that Mr. Munden would have been entitled to receive to the end of the term had his employment contract remained in place. Mr. Munden has agreed to make himself available as a consultant for up to 1 hour per week for a period of 6 months following the effective date of his termination of employment. On August 6, 2000, in connection with our decision to close our Ottawa office, the Board also notified Mr. Barr that it required him to relocate to Dallas on or before November 6, 2001. Mr. Barr declined to relocate. The Company entered into a termination severance agreement with Mr. Barr under which Mr. Barr agreed to resign his officer positions effective August 31, 2001 and to resign his employment on the earlier of his receipt of written notice from the Company or November 6, 2001. As a settlement of the Company's obligations under Mr. Barr's employment contract, the Company agreed to pay Mr. Barr the amount of $157,603 consisting of his Base Salary through November 6, 2001 plus a severance payment equal to the sum of 1 year's Base Salary plus accrued Target Bonus (as those capitalized terms were defined in his employment contract). In addition, the Company agreed to issue 25,000 warrants to Mr. Barr to replace the options that he had been previously granted. The warrants have an exercise price of $7.00 per share and will expire on February 24, 2003. In the event that a Change of Control (as that term is defined in Mr. Barr's employment contract) occurs at any time through March 31, 2003, the Company will pay Mr. Barr an additional amount of one half his annual Base Salary (the Comstock transaction will 24 constitute a change of control). As part of the severance package, the Company also agreed to pay Mr. Barr an additional cash payment of $16,000 which is the equivalent amount of the fringe benefits that he would have been entitled to receive to the end of the term had his employment contract remained in place. Mr. Barr's termination agreement also contains a general release and a non-competition clause and provides for the surrender and cancellation of all options previously granted to Mr. Barr. Mr. Barr has agreed to make himself available as a consultant for up to 5 hours per month for a period of 12 months following the effective date of his termination of employment. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) EXHIBITS. 10.1 Termination agreement with Edward J. Munden dated as of August 31, 2001. 10.2 Termination agreement with Brian J. Barr dated as of August 31, 2001. 10.3 Form of share purchase warrant issued to Edward J. Munden and Brian J. Barr, incorporated in reference from the Company's Registration Statement on Form S-8 filed on November 2, 2001. (b) REPORTS ON FORM 8-K. Current report on Form 8-K dated August 31, 2001, filed September 12, 2001, pursuant to Item 5 reporting the closing of the Ottawa office and a stock repurchase program. 25 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized this 14th day of November 2001. DEVX ENERGY, INC. (DELAWARE) By: /s/ Joseph T. Williams ----------------------------------------------- Joseph T. Williams Chairman, President and Chief Executive Officer By: /s/ William W. Lesikar ----------------------------------------------- William W. Lesikar Chief Financial Officer DEVX ENERGY, INC. (NEVADA) By: /s/ Joseph T. Williams ----------------------------------------------- Joseph T. Williams Chairman, President and Chief Executive Officer By: /s/ William W. Lesikar ----------------------------------------------- William W. Lesikar Vice President (Principal Financial Officer) DEVX OPERATING COMPANY By: /s/ Joseph T. Williams ----------------------------------------------- Joseph T. Williams Chairman, President and Chief Executive Officer By: /s/ William W. Lesikar ----------------------------------------------- William W. Lesikar Vice President (Principal Financial Officer) CORRIDA RESOURCES, INC. By: /s/ Joseph T. Williams ----------------------------------------------- Joseph T. Williams Chairman, President and Chief Executive Officer By: /s/ William W. Lesikar ----------------------------------------------- William W. Lesikar Treasurer (Principal Financial Officer) 26 INDEX TO EXHIBITS

EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.1 Termination agreement with Edward J. Munden dated as of August 31, 2001. 10.2 Termination agreement with Brian J. Barr dated as of August 31, 2001. 10.3 Form of share purchase warrant issued to Edward J. Munden and Brian J. Barr, incorporated in reference from the Company's Registration Statement on Form S-8 filed on November 2, 2001.