10-Q 1 d89683e10-q.txt FORM 10-Q FOR QUARTER ENDED JUNE 30, 2001 1 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 JUNE 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 August 1, 2001: 12,748,612 2 PART I FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)

See accompanying notes to unaudited consolidated condensed financial statements. 1 3 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

See accompanying notes to unaudited consolidated condensed financial statements. 2 4 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

See accompanying notes to unaudited consolidated condensed financial statements. 3 5 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS JUNE 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 its 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 ended June 30, 2001 are not necessarily indicative of the operating results for the full fiscal 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. 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 June 30, 2001, the Company recognized a decrease in the derivative liability and an associated decrease in other comprehensive loss totaling approximately $5,179,000. During the six months ended June 30, 2001, the Company recognized a decrease in the derivative liability and an associated decrease in other comprehensive loss totaling approximately $8,062,000. As of June 30, 2001, other current assets included $963,000 and other assets include $938,000 related to the fair value of derivative contracts. During the three and six months ended June 30, 2001, the Company recognized non-cash gains of $1,736,000 and $3,195,000, respectively, in earnings related to the net change in fair value of derivative contracts which have not been designated as hedges. During the three and six months ended June 30, 2001, the Company paid $1,081,000 and $3,892,000, respectively, in cash settlements on its natural gas hedges which are included in net profits and royalty interests. 4 6 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 June 30, 2001, the Company's comprehensive income differed from net income by approximately $5,179,000 related to the change in fair value of a natural gas swap contract designated as a hedge. There were no differences between comprehensive income and net income for the three months ended June 30, 2000. For the six-month period ending June 30, 2001, the Company's comprehensive income differed from net income by approximately $8,062,000 related to the change in fair market value of a natural gas swap contract designated as a hedge. There were no differences between comprehensive income and net loss for the six months ended June 30, 2000. 4. EARNINGS (LOSS) PER SHARE The following table sets forth the computation of basic and diluted earnings per common share:

Weighted average common shares outstanding and losses per common share for the three and six months ended June 30, 2000 have been restated for the effects of a 156-to-1 reverse stock split. 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 5 7 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 ended June 30, 2001 will not necessarily be indicative of the operating results for the full fiscal year ending December 31, 2001.

----------------- (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 and change in derivative fair value. 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 $424,000 of amortized deferred charges related to debt obligations and $0 and $22,000 of amortized deferred charges related to the Company's natural gas price-hedging program for the three months ended June 30, 2001 and 2000, respectively. Depreciation, depletion and amortization includes $398,000 and $824,000 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 six months ended June 30, 2001 and 2000, respectively. 6 8

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 JUNE 30, 2001 COMPARED TO THE THREE MONTHS ENDED JUNE 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 $1.1 million, or 11%, to $10.7 million for the three months ended June 30, 2001 from $9.6 million during the comparable period in 2000. Natural gas contributed 89% of our total revenues for the June 2001 quarter and 84% during the June 2000 quarter. Our production of both oil and natural gas decreased for second quarter 2001 compared with second 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 continued to decline. 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. We have increased development expenditures and initiated an on-going exploration effort, both of which are intended to increase our production rates and proven reserves. We produced 44,000 barrels of crude oil during the three months ended June 30, 2001, a decrease of 9,000 barrels, or 17%, from the 53,000 barrels produced during the comparable period in 2000. We produced 2.3 Bcf of natural gas during the three months ended June 30, 2001, a decrease of 227 MMcf, or 9%, from the 2.5 Bcf produced during the comparable period in 2000. This decrease consists of a decrease of 187 MMcf, or 8%, from the properties that we owned during both periods and a decrease of 7 9 40 MMcf from the properties that we sold at the end of June 2000. The production during the second quarter of 2001 was impacted by decreases due to natural decline 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. In June 2001, sales to this market were permanently discontinued. At that time, we were building additional gathering lines to service existing and future wells and should be connecting all wells to an interstate transmission line during September 2001. Our development activity in the field is continuing, and we are currently drilling 50 wells utilizing two drilling rigs. Completing operations on new wells will begin during August 2001. On a thousand cubic feet of natural gas equivalent ("Mcfe") basis, production for the three months ended June 30, 2001 was 2.5 Bcfe, down 0.3 Bcfe, or 10%, from the 2.8 Bcfe produced during the comparable period in 2000. Production from properties that we owned during both periods was down 239 MMcfe, or 9%, during the three months ended June 30, 2001 when compared to production during the three months ended June 30, 2000. The increase in revenue is due to a significant industry-wide increase in natural gas prices which reached historic highs during the first quarter of 2001. Natural gas prices during second quarter 2001 were below first quarter levels but remained well above second quarter 2000 prices. The average price per Mcf of natural gas sold by us was $4.18 during the three months ended June 30, 2001, an increase of $0.98 per Mcf, or 30%, over the $3.20 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 June 30, 2001 was $25.83, a decrease of $3.33 per barrel, or 11%, below the $29.16 per barrel during the three months ended June 30, 2000. On a Mcfe basis, the average price received by us during the three months ended June 30, 2001 was $4.19, a $0.80 increase, or 24%, over the $3.39 we received during the comparable period in 2000. During the three months ended June 30, 2001, we paid $1,081,000 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 $0.47 per Mcf. During the comparable period in 2000, we paid $564,000 in cash settlements and amortized $22,000 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 three months ended June 30, 2001, no crude oil price-hedging contracts were in place. During the comparable period in 2000, we paid $20,000 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 $221,000 during the three months ended June 30, 2001 compared to $474,000 during the comparable period in 2000. This decrease of $253,000, or 53%, is primarily the result of receiving severance tax rebates in our Gilmer and J.C. Martin fields. On a cost per Mcfe basis, severance taxes were $0.09 per Mcfe for the three months ended June 30, 2001 compared to $0.17 per Mcfe for the comparable period ending June 30, 2000, a decrease of 48%. PRODUCTION EXPENSES: Our lease operating expenses increased to $1.7 million for the three months ended June 30, 2001, an increase of $0.3 million, or 31%, from the $1.4 million incurred during the comparable period in 2000. This is due to higher ad valorem tax accruals in this period compared to the comparable period in 2000. Lease operating expenses were $0.65 per Mcfe during the three months ended June 30, 2001, an increase of $0.15, or 30%, from the $0.50 per Mcfe incurred during the comparable period in 2000. The increase in average costs per unit is a result of higher ad valorem tax accruals 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 June 30, 2001, an increase of 15% over the $2.1 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 three months, an increase of $0.21 per Mcfe, or 30%, from the 8 10 $0.72 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 $394,000, or 49%, in general and administrative costs for the three months ended June 30, 2001 is a result of increased audit fees and engineering costs; increased franchise taxes; and increased employee-related costs. INTEREST EXPENSE: Interest expense decreased by $2.8 million to $1.8 million for the three months ended June 30, 2001 compared to $4.7 million for the three months ended June 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 June 30, 2000, there were $0.4 million of amortized deferred debt issuance costs included in the interest expense of $4.7 million. CHANGE IN DERIVATIVE FAIR VALUE: During the quarter ended June 30, 2001, we recorded a gain of $1.7 million representing the change in fair value of our derivative contracts that are not accounted for as hedges. We adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), on July 1, 2000. Accordingly, no comparable amounts were recorded during the quarter ended June 30, 2000. NET INCOME: For the three months ended June 30, 2001, we recorded net income of $3.4 million or $0.27 and $0.26 per basic and diluted share, respectively, compared to income of $0.2 million or $0.50 per basic and $0.15 per diluted share for 2000. The reduction of debt and increased natural gas prices are the primary causes of the significantly improved results. THE SIX MONTHS ENDED JUNE 30, 2001 COMPARED TO THE SIX MONTHS ENDED JUNE 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 $7.1 million, or 41%, to $24.6 million for the six months ended June 30, 2001 from $17.5 million during the comparable period in 2000. Natural gas contributed 90% of our total revenues for the six months ended June 2001 and 83% during the comparable period in 2000. Our production of both oil and natural gas decreased for the six months ended June 30, 2001 compared with the six months ended June 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 continued to decline. 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. We have increased development expenditures and initiated an on-going exploration effort, both of which are intended to increase our production rates and proven reserves. We produced 87,000 barrels of crude oil during the six months ended June 30, 2001, a decrease of 23,000 barrels, or 20%, from the 110,000 barrels produced during the comparable period in 2000. We produced 4.5 Bcf of natural gas during the six months ended June 30, 2001, a decrease of 576 MMcf, or 11%, from the 5.1 Bcf produced during the comparable period in 2000. This decrease consists of a decrease of 458 MMcf, or 9%, from 9 11 the properties that we owned during both periods and a decrease of 118 MMcf from the properties that we sold at the end of June 2000. The production during the first six months of 2001 was impacted by decreases due to natural decline 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. In June 2001, sales to this market were permanently discontinued. At that time, we were building additional gathering lines to service existing and future wells and should be connecting all wells to an interstate transmission line during September 2001. Our development activity in the field is continuing, and we are currently drilling 50 wells utilizing two drilling rigs. Completing operations on new wells will begin during August 2001. On a thousand cubic feet of natural gas equivalent ("Mcfe") basis, production for the six months ended June 30, 2001 was 5.0 Bcfe, down 0.7 Bcfe, or 12%, from the 5.7 Bcfe produced during the comparable period in 2000. Production from properties that we owned during both periods was down 589 MMcfe, or 10%, during the six months ended June 30, 2001 when compared to production during the six months ended June 30, 2000. The increase in revenues was due to a significant, industry-wide increase in natural gas prices, partially offset by lower production volume and slightly lower oil prices. The average price per barrel of crude oil sold by us during the six months ended June 30, 2001 was $27.06, a decrease of $0.27 per barrel, or 1%, below the $27.33 per barrel during the six months ended June 30, 2000. The average price per Mcf of natural gas sold by us was $4.93 during the six months ended June 30, 2001, an increase of $2.08 per Mcf, or 73%, over the $2.85 per Mcf during the comparable period in 2000. During the six months ended June 30, 2001, we paid $3,892,000 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 $0.86 per Mcf. During the comparable period in 2000, we paid $616,000 in cash settlements and amortized $44,000 of deferred hedging costs regarding our natural gas price-hedging program. The net negative effect on the average natural gas prices we received during the 2000 period was $0.12 per Mcf. During the six months ended June 30, 2001, no crude oil price-hedging contracts were in place. During the comparable period in 2000, we paid $109,000 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 $882,000 during the six months ended June 30, 2001 compared to $847,000 during the comparable period in 2000. This increase of $35,000, or 4%, is primarily the result of increased revenues we received during the six months ended June 30, 2001, offset by severance tax rebates on our Gilmer and J.C. Martin fields received during the first six months of 2001. On a cost per Mcfe basis, severance taxes were $0.18 per Mcfe for the six months ended June 30, 2001 compared to $0.15 per Mcfe for the comparable period ending June 30, 2000, an increase of 19%. Average wellhead prices rose by 78% from $3.17 per Mcfe during the six months ended June 30, 2000 to $5.65 per Mcfe during the six months ended June 30, 2001. PRODUCTION EXPENSES: Our lease operating expenses increased to $3.4 million for the six months ended June 30, 2001, an increase of $0.5 million, or 17%, from the $2.9 million incurred during the comparable period in 2000. This increase is due to increased ad valorem tax accruals during the six months ended June 30, 2001 compared to the six months ended June 30, 2000. Lease operating expenses were $0.68 per Mcfe during the six months ended June 30, 2001, an increase of $0.17, or 34%, from the $0.51 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 $4.7 million for the six months ended June 30, 2001, an increase of 9% over the $4.3 million for the comparable period in 2000. On a Mcfe basis, depletion and oil field equipment related 10 12 depreciation was $0.92 per Mcfe during the six months, an increase of $0.19 per Mcfe, or 26%, from the $0.73 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 $537,000, or 35%, in general and administrative costs for the 6-month period ending June 30, 2001 is a result of increased audit fees; increased regulatory fees, mainly franchise taxes; increased employee-related costs; and increased engineering costs. INTEREST EXPENSE: Interest expense decreased by $5.7 million to $3.7 million for the six months ended June 30, 2001 compared to $9.4 million for the six months ended June 30, 2000. The interest expense of $3.7 million is comprised of $3.3 million in cash interest charges and $0.4 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 six months ended June 30, 2000, there were $0.8 million of amortized deferred debt issuance costs included in the interest expense of $9.4 million. CHANGE IN DERIVATIVE FAIR VALUE: During the six months ended June 30, 2001, we recorded a gain of $3.2 million representing the change in fair value of our derivative contracts that are not accounted for as hedges. We adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), on July 1, 2000. Accordingly, no comparable amounts were recorded during the six months ended June 30, 2000. NET INCOME: For the six months ended June 30, 2001, we recorded net income of $8.4 million or $0.66 and $0.65 per basic and diluted share, respectively, compared to a loss of $1.4 million or $4.25 per basic and diluted share for 2000. The reduction of debt and increased natural gas prices are the primary causes of the significantly improved results. 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, and 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 $9.7 million during the first six months of 2001, including $2.3 million in exploration activities. Our plans for the remainder of 2001 call for additional capital spending ranging between $17 million and $20 million, of which 15% to 25% is allocated to exploration activities. The increased spending levels are intended to increase our reserves and production rates. We intend to fund the investing activities using our existing cash balances, cash generated from operations and, to the extent necessary, our revolving credit facility. We have planned development and exploitation activities for all of our major operating areas. We plan to spend a total of $27-30 million in capital activities during 2001. During the six months ended June 30, 2001, we have spent $9.7 million and have a further $11.3 million contractually committed. Of the total planned capital expenditures for the year, 18-24% is allocated to exploration activities. We believe our cash flow from operations combined with our existing credit facility will be sufficient to fund our planned exploration, development and exploitation activities for 2001. In addition, we are continuing to evaluate oil and natural gas properties for future acquisition. Historically, 11 13 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. 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. None of the indications of interest have resulted in a definitive agreement. Natural gas prices have decreased during the past few months, and that decrease has reduced the value prospective buyers place on the Company. We continue to have discussions with prospective buyers and merger partners, continuing to seek a price that we believe is a fair and reasonable valuation of the Company. 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 August 1, 2001, under this facility, we had no indebtedness outstanding, had $3.4 million reserved to secure a letter of credit, and were permitted to borrow an additional $40.1 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%; 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 six months ended June 30, 2001. We have a letter of credit outstanding under the credit agreement in the amount of $3.4 million, as of August 1, 2001, to secure a swap exposure. The letter of credit has the effect of reducing our credit availability under the credit agreement. 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 12 14 exploitation of our oil and natural gas properties. We have recently entered into two exploration joint ventures and expect to allocate 18-24% of our 2001 capital spending to exploration activities. We expect to spend $27-30 million on capital spending during 2001 for exploitation, development and exploration projects. As of June 30, 2001, we are contractually obligated to fund $11.3 million in capital expenditures through December 2001. We believe that cash flow from operations and our credit agreement will be sufficient to fund our planned activities. However, our cash flow from operations is significantly affected by the uncertainty of commodity prices. If there were a significant, protracted decline in prices, we would evaluate our projects and may delay or defer some of our planned activities. During the six months ended June 30, 2001, we recorded $9.7 million in capital expenditures. Of this amount, $2.3 million relate to exploration activities with the balance of $7.4 million used in property development. 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 such financing, if obtained, will be on terms favorable to us. 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. Our credit agreement permits up to $12 million in letters of credit. As of August 1, 2001, we have provided $3.4 million in letters of credit related to our hedge contracts containing "caps." 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. 13 15

We have a commodity price risk management or hedging strategy that is designed to provide protection from low commodity prices while providing some opportunity to enjoy the benefits of higher commodity prices. We have a series of natural gas futures contracts with various counter-parties. This strategy is designed to provide a degree of protection from negative shifts in natural gas prices as reported on the Henry Heb 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:

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:

14 16 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:

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:

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." 15 17 PART II OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS A portion of our royalty interest in the J.C. Martin field, which comprises approximately 8% of our total SEC PV-10 value as of December 31, 2000, is currently subject to a lawsuit issued by a former owner against the pension funds managed by the entity that sold us our royalty interest in the properties in 1998. We are not parties to the lawsuit. Among other things, the lawsuit seeks rescission of the 1989 sale of the properties to the pension funds from whom we obtained our royalty interest and, accordingly, may create uncertainty as to our title. On November 5, 1997, a summary judgment order was issued in favor of the defendants dismissing the plaintiff's title claims. The plaintiff's appeal of that order was dismissed on May 10, 2001. The plaintiff's application for a rehearing of the first appeal was rejected on June 7, 2001. On July 23, 2001, the plaintiff filed an application for leave to further appeal the order for summary judgment to a higher court. It is not known when a decision on the leave application will be issued. If the leave application is granted, an appeal hearing will be scheduled in due course. A dismissal of the leave application will effectively terminate the lawsuit as it pertains to the title issue. Although we are of the view that the plaintiff's case is without merit, there can be no assurance that the motion for leave to appeal will not be granted, or if leave is granted, that the appeal will not succeed. Eight million dollars of the purchase price we paid for the Morgan Properties, which include our royalty interest in the J.C. Martin field, were placed in an interest bearing escrow account pending the resolution of this lawsuit. As of June 30, 2001, the balance in the escrow account inclusive of interest was approximately $9.4 million. If the summary judgment is overturned on appeal and a final judgment is later entered against the entity who sold us this property and that judgment unwinds the original transaction in which the entity acquired its interest in the J.C. Martin field, the balance in the escrow account would be returned to us and we would be required to convey our royalty interest, plus production proceeds, in the J.C. Martin field to the plaintiff retroactive to the date we acquired the interest. 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. None of the indications of interest have resulted in a definitive agreement. Natural gas prices have decreased during the past few months, and that decrease has reduced the value prospective buyers place on the company. We continue to have discussions with prospective buyers and merger partners, continuing to seek a price that we believe is a fair and reasonable valuation of the company. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (A) EXHIBITS. None. (B) REPORTS ON FORM 8-K. None. 16 18 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 9th day of August 2001. DEVX ENERGY, INC. (DELAWARE) By: /s/ Edward J. Munden ----------------------------------- Edward J. Munden President and Chief Executive Officer By: /s/ William W. Lesikar ----------------------------------- William W. Lesikar Chief Financial Officer DEVX ENERGY, INC. (NEVADA) By: /s/ Edward J. Munden ----------------------------------- Edward J. Munden President and Chief Executive Officer By: /s/ William W. Lesikar ----------------------------------- William W. Lesikar Vice President (Principal Financial Officer) DEVX OPERATING COMPANY By: /s/ Edward J. Munden ----------------------------------- Edward J. Munden President and Chief Executive Officer By: /s/ William W. Lesikar ----------------------------------- William W. Lesikar Vice President (Principal Financial Officer) CORRIDA RESOURCES, INC. By: /s/ Edward J. Munden ----------------------------------- Edward J. Munden President and Chief Executive Officer By: /s/ William W. Lesikar ----------------------------------- William W. Lesikar Treasurer (Principal Financial Officer)

DEVX ENERGY INC 10-Q