UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) Quarterly Report Under Section 13 or 15(d) [X] of the Securities Exchange Act of 1934 For the Quarterly Period Ended June 30, 2002 or Transition Report Pursuant to Section 13 or 15(d) [ ] of the Securities Act of 1934 for the Transition Period from _____ to _____ COMMISSION FILE NO. 1-10762 ---------- HARVEST NATURAL RESOURCES, INC. (Exact name of registrant as specified in its charter) DELAWARE 77-0196707 (State or other jurisdiction of (I.R.S. Employer Identification Number) incorporation or organization) 15835 PARK TEN PLACE DRIVE, SUITE 115 HOUSTON, TEXAS 77084 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (281) 579-6700 BENTON OIL AND GAS COMPANY (former name, former address, and former fiscal year if changed since last report) 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 --- --- At August 5, 2002, 35,020,905 shares of the Registrant's Common Stock were outstanding. 2 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES <Table> <Caption> Page PART I FINANCIAL INFORMATION Item 1. FINANCIAL STATEMENTS Unaudited Consolidated Balance Sheets at June 30, 2002 and December 31, 2001....................................................................3 Unaudited Consolidated Statements of Income for the Three and Six Months Ended June 30, 2002 and 2001......................................................4 Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2002 and 2001......................................................5 Notes to Consolidated Financial Statements......................................................7 Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS..............................................................17 Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.......................................25 PART II OTHER INFORMATION Item 1. LEGAL PROCEEDINGS................................................................................26 Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS........................................................26 Item 3. DEFAULTS UPON SENIOR SECURITIES..................................................................26 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............................................27 Item 5. OTHER INFORMATION................................................................................27 Item 6. EXHIBITS AND REPORTS ON FORM 8-K.................................................................27 SIGNATURES...............................................................................................................28 </Table> 3 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands) <Table> <Caption> JUNE 30, DECEMBER 31, 2002 2001 ----------- ------------ (unaudited) ASSETS CURRENT ASSETS: Cash and cash equivalents $ 56,709 $ 9,024 Restricted cash 12 12 Marketable securities 12,892 -- Accounts and notes receivable: Accrued oil revenue 32,393 23,138 Joint interest and other, net 6,108 9,520 Prepaid expenses and other 3,811 1,839 ----------- ------------ TOTAL CURRENT ASSETS 111,925 43,533 RESTRICTED CASH 16 16 OTHER ASSETS 3,191 4,718 DEFERRED INCOME TAXES 4,779 57,700 INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES 48,863 100,498 PROPERTY AND EQUIPMENT: Oil and gas properties (full cost method - costs of $3,477 and $16,892 excluded from amortization in 2002 and 2001, respectively) 553,909 533,950 Furniture and fixtures 7,687 7,399 ----------- ------------ 561,596 541,349 Accumulated depletion, impairment and depreciation (427,479) (399,663) ----------- ------------ 134,117 141,686 ----------- ------------ $ 302,891 $ 348,151 =========== ============ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade and other $ 10,702 $ 8,132 Accrued expenses 21,299 25,840 Accrued interest payable 1,511 3,894 Income taxes payable 11,282 3,821 Current portion of long-term debt 1,890 2,432 ----------- ------------ TOTAL CURRENT LIABILITIES 46,684 44,119 LONG-TERM DEBT 90,198 221,583 COMMITMENTS AND CONTINGENCIES -- -- MINORITY INTEREST 18,237 14,826 STOCKHOLDERS' EQUITY: Preferred stock, par value $0.01 a share; authorized 5,000 shares; outstanding, none -- -- Common stock, par value $0.01 a share; authorized 80,000 shares; issued 34,417 shares at June 30, 2002 and 34,164 shares at December 31, 2001 350 342 Additional paid-in capital 170,444 168,108 Accumulated deficit (22,323) (100,128) Treasury stock, at cost, 50 shares (699) (699) ----------- ------------ TOTAL STOCKHOLDERS' EQUITY 147,772 67,623 ----------- ------------ $ 302,891 $ 348,151 =========== ============ </Table> See accompanying notes to consolidated financial statements. 4 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data, unaudited) <Table> <Caption> THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------ -------------------------- 2002 2001 2002 2001 -------- -------- -------- -------- REVENUES Oil sales $ 33,022 $ 32,844 $ 60,269 $ 67,182 -------- -------- -------- -------- 33,022 32,844 60,269 67,182 -------- -------- -------- -------- EXPENSES Operating expenses 8,437 9,641 15,855 22,505 Depletion, depreciation and amortization 7,334 6,799 14,774 12,705 Write-downs of oil and gas properties and impairments 13,427 411 13,427 411 General and administrative 5,326 5,691 8,604 10,420 Taxes other than on income 1,223 1,951 1,807 3,126 -------- -------- -------- -------- 35,747 24,493 54,467 49,167 -------- -------- -------- -------- (2,725) 8,351 5,802 18,015 INCOME (LOSS) FROM OPERATIONS OTHER NON-OPERATING INCOME (EXPENSE) Gain on disposition of assets 142,977 -- 142,977 -- Gain on early extinguishment of debt 874 -- 874 -- Investment income and other 1,210 863 1,716 1,663 Interest expense (4,500) (6,154) (11,009) (12,338) Net gain on exchange rates 2,379 139 4,434 219 -------- -------- -------- -------- 142,940 (5,152) 138,992 (10,456) -------- -------- -------- -------- INCOME FROM CONSOLIDATED COMPANIES BEFORE INCOME TAXES AND MINORITY INTERESTS 140,215 3,199 144,794 7,559 INCOME TAX EXPENSE 59,692 3,881 61,493 7,077 -------- -------- -------- -------- INCOME (LOSS) BEFORE MINORITY INTERESTS 80,523 (682) 83,301 482 MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY COMPANIES 2,031 1,541 3,411 2,834 -------- -------- -------- -------- INCOME (LOSS) FROM CONSOLIDATED COMPANIES 78,492 (2,223) 79,890 (2,352) EQUITY IN NET EARNINGS (LOSSES) OF AFFILIATED COMPANIES (2,172) 1,061 (2,085) 3,475 -------- -------- -------- -------- NET INCOME (LOSS) $ 76,320 $ (1,162) $ 77,805 $ 1,123 ======== ======== ======== ======== NET INCOME (LOSS) PER COMMON SHARE: Basic $ 2.20 $ (0.03) $ 2.26 $ 0.03 ======== ======== ======== ======== Diluted $ 2.10 $ (0.03) $ 2.18 $ 0.03 ======== ======== ======== ======== </Table> See accompanying notes to consolidated financial statements. 5 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands, unaudited) <Table> <Caption> SIX MONTHS ENDED JUNE 30, ------------------------------ 2002 2001 --------- -------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 77,805 $ 1,123 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization 14,774 12,705 Write-downs of oil and gas properties 13,427 411 Amortization of financing costs 1,464 698 Gain on disposition of assets (142,977) -- Gain on early extinguishment of debt (874) -- Equity in (earnings) losses of affiliated companies 2,085 (3,475) Allowance for employee notes and accounts receivable 164 164 Non-cash compensation-related charges 503 244 Minority interest in undistributed earnings of subsidiaries 3,411 2,834 Deferred income taxes 52,921 (224) Changes in operating assets and liabilities: Accounts and notes receivable (6,007) 5,883 Prepaid expenses and other (1,972) 306 Accounts payable 2,570 (2,114) Accrued expenses (10,485) 448 Accrued interest payable (2,383) 168 Income taxes payable 7,461 4,812 --------- -------- NET CASH PROVIDED BY OPERATING ACTIVITIES 11,887 23,983 --------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sale of investments 189,841 -- Additions of property and equipment (20,715) (22,205) Investment in and advances to affiliated companies 8,713 (6,776) Increase in restricted cash -- (57) Decrease in restricted cash -- 10,961 Purchase of marketable securities (46,642) (15,067) Maturities of marketable securities 33,750 16,370 --------- -------- NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 164,947 (16,774) --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from exercise of stock options 1,841 -- Proceeds from issuance of short-term borrowings and notes payable -- 19,973 Payments on short-term borrowings and notes payable (131,053) (13,818) (Increase) decrease in other assets 63 (167) --------- -------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (129,149) 5,988 --------- -------- NET INCREASE IN CASH AND CASH EQUIVALENTS 47,685 13,197 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,024 15,132 --------- -------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 56,709 $28,329 ========= ======== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid during the period for interest expense $ 13,326 $ 12,860 ========= ======== Cash paid during the period for income taxes $ 1,426 $ 1,142 ========= ======== </Table> See accompanying notes to consolidated financial statements. 6 SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES During the six months ended June 30, 2002 and 2001, we recorded an allowance for doubtful accounts related to amounts owed to us by our former Chief Executive Officer including the portions of the note secured by our stock and stock options (see Note 11). See accompanying notes to consolidated financial statements. 7 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS THREE AND SIX MONTHS ENDED JUNE 30, 2002 (UNAUDITED) NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INTERIM REPORTING In our opinion, the accompanying unaudited consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of June 30, 2002, and the results of operations for the three and six month periods ended June 30, 2002 and 2001 and cash flows for the six month periods ended June 30, 2002 and 2001. The unaudited financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America. Reference should be made to our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2001, for additional disclosures, including a summary of our accounting policies. The results of operations for the three and six month periods ended June 30, 2002 are not necessarily indicative of the results to be expected for the full year. ORGANIZATION We engage in the exploration, development, production and management of oil and gas properties. We conduct our business principally in Venezuela and Russia. Effective May 20, 2002, we changed our name to Harvest Natural Resources, Inc. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of all wholly owned and majority owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated. We account for our investment in Geoilbent, Ltd. ("Geoilbent") and Arctic Gas Company ("Arctic Gas") based on a fiscal year ending September 30 (see Note 2). USE OF ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statement and the reported amounts of revenue and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and future development costs. Actual results could differ from those estimates. ACCOUNTS AND NOTES RECEIVABLE Allowance for doubtful accounts related to employee notes was $6.7 million and $6.5 million at June 30, 2002 and December 31, 2001, respectively (see Note 11). MINORITY INTERESTS We record a minority interest attributable to the minority shareholders of our subsidiaries. The minority interests in net income and losses are generally subtracted or added to arrive at consolidated net income. MARKETABLE SECURITIES Marketable securities are carried at amortized cost. The marketable securities we may purchase are limited to those defined as Cash Equivalents in the indentures for our senior unsecured note. Cash Equivalents may be comprised of high-grade debt instruments, demand or time deposits, bankers' acceptances and certificates of deposit or acceptances of large U.S. financial institutions and commercial paper of highly rated U.S. corporations, all having maturities of no more than 180 days. Our marketable securities at cost, which approximates fair value, consisted of $12.9 million in commercial paper at June 30, 2002. 8 COMPREHENSIVE INCOME Statement of Financial Accounting Standards No. 130 ("SFAS 130") requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. We did not have any items of other comprehensive income during the three and six month periods ended June 30, 2002 or June 30, 2001 and, in accordance with SFAS 130, have not provided a separate statement of comprehensive income. DERIVATIVES AND HEDGING Statement of Financial Accounting Standards No. 133 ("SFAS 133"), as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. We have not used derivative or hedging instruments since 1996. EARNINGS PER SHARE Basic earnings per common share ("EPS") is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 34.7 million and 34.4 million for the three and six months ended June 30, 2002, respectively, and 33.9 million for each of the three and six months ended June 30, 2001. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 36.4 million and 35.7 million for the three and six months ended June 30, 2002, respectively, and 33.9 million and 34.0 million for the three and six months ended June 30, 2001, respectively. PROPERTY AND EQUIPMENT We follow the full cost method of accounting for oil and gas properties with costs accumulated in cost centers on a country by country basis, subject to a cost center ceiling (as defined by the Securities and Exchange Commission). All costs associated with the acquisition, exploration, and development of oil and natural gas reserves are capitalized as incurred, including exploration overhead of $0.4 million for the six months ended June 30, 2001, and capitalized interest of $0.5 million and $0.4 million for the six months ended June 30, 2002 and 2001, respectively. Only overhead that is directly identified with acquisition, exploration or development activities is capitalized. All costs related to production, general corporate overhead and similar activities are expensed as incurred. The costs of unproved properties are excluded from amortization until the properties are evaluated. Excluded costs attributable to the China and other cost centers were $3.5 million and $16.9 million at June 30, 2002 and December 31, 2001, respectively. We regularly evaluate our unproved properties on a country by country basis for possible impairment. If we abandon all exploration efforts in a country where no proved reserves are assigned, all exploration and acquisition costs associated with the country are expensed. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty. Of the $3.5 million, $2.9 million relates to the acquisition of Benton Offshore China Company and exploration expenditures related to its WAB-21 property (See Note 10). The remaining $0.6 million at June 30, 2002 relates to the Lakeside Prospect. All capitalized costs and estimated future development costs (including estimated dismantlement, restoration and abandonment costs) of proved reserves are depleted using the units of production method based on the total proved reserves of the country cost center. Depletion expense, which was substantially all attributable to the Venezuelan cost center for the six months ended June 30, 2002 and 2001, was $14.1 million and $10.6 million ($2.82 and $2.12 per equivalent barrel), respectively. Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally five years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $0.6 million and $1.7 million for the three months ended June 30, 2002 and 2001, respectively. Depreciation expense was $0.7 million and $2.1 million for the six months ended June 30, 2002, respectively. NEW ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact of SFAS No. 143 and therefore, at this time, cannot reasonably estimate the effect of this statement on its consolidated financial position, results of operations or cash flows. 9 In May 2002, the FASB issued SFAS No. 145, Recission of FASB Statements No. 44, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS 145 rescinds the automatic treatment of gains or losses from extinguishment of debt as extraordinary items as outlined in APB Opinion No. 30, "Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions". As allowed under the provisions of SFAS 145, we had decided to early adopt SFAS 145 (See Note 3). In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. SFAS 146 replaces Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)". NOTE 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES Investments in Geoilbent and Arctic Gas are accounted for using the equity method due to the significant influence we exercise over their operations and management. Investments include amounts paid to the investee companies for shares of stock or joint venture interests and other costs incurred associated with the acquisition and evaluation of technical data for the oil and natural gas fields operated by the investee companies. Other investment costs are amortized using the units of production method based on total proved reserves of the investee companies. On February 27, 2002, we entered into a Sale and Purchase Agreement to sell our entire 68 percent stock ownership interest in Arctic Gas Company to a nominee of the Yukos Oil Company for $190 million plus approximately $30 million as repayment of intercompany loans owed to us by Arctic Gas ("Arctic Gas Sale"). On March 28, 2002, we received the first payment ($121.0 million) of proceeds. On April 12, 2002, we received the balance of the sales proceeds plus repayment of the intercompany loan, and transferred the Arctic Gas shares. Equity in earnings of Geoilbent and Arctic Gas are based on a fiscal year ending September 30. Arctic Gas equity earnings for the twelve days of April will be reflected in the three months ending September 30, 2002. No dividends have been paid to us from Geoilbent or Arctic Gas. Equity in earnings and losses and investments in and advances to companies accounted for using the equity method are as follows (in thousands): <Table> <Caption> GEOILBENT, LTD. ARCTIC GAS COMPANY TOTAL -------------------------- ------------------------- --------------------------- JUNE 30, DECEMBER 31, JUNE 30, DECEMBER 31, JUNE 30, DECEMBER 31, 2002 2001 2002 2001 2002 2001 -------- ------------ -------- ------------ -------- ------------ Investments Equity in net assets $ 28,056 $ 28,056 $ -- $ (1,814) $ 28,056 $ 26,242 Other costs, net of amortization 106 (99) -- 28,579 106 28,480 -------- ------------ -------- ------------ -------- ------------ Total investments 28,162 27,957 -- 26,765 28,162 54,722 Advances 2,502 -- -- 28,829 2,502 28,829 Equity in earnings (losses) 18,199 19,307 -- (2,360) 18,199 16,947 -------- ------------ -------- ------------ -------- ------------ Total $ 48,863 $ 47,264 $ -- $ 53,234 $ 48,863 $ 100,498 ======== ============ ======== ============ ======== ============ </Table> 10 NOTE 3 - LONG-TERM DEBT AND LIQUIDITY LONG-TERM DEBT Long-term debt consists of the following (in thousands): <Table> <Caption> JUNE 30, DECEMBER 31, 2002 2001 ------------ ------------ Senior unsecured notes with interest at 9.375%. See description below. $ 85,000 $ 105,000 Senior unsecured notes with interest at 11.625%. -- 108,000 Note payable with interest at 7.04%. See description below. 4,800 5,100 Note payable with interest at 44.47%. See description below. 2,288 5,235 Non-interest bearing liability with a face value of $744 discounted at 7%. See description below -- 680 ------------ ------------ 92,088 224,015 Less current portion 1,890 2,432 ------------ ------------ $ 90,198 $ 221,583 ============ ============ </Table> In May 1996, we issued $125 million in 11.625 percent senior unsecured notes due May 1, 2003 ("2003 Notes"), of which we had previously repurchased $17 million in prior periods and the remaining $108 million at March 29, 2002. In November 1997, we issued $115 million in 9.375 percent senior unsecured notes due November 1, 2007 ("2007 Notes"), of which we earlier repurchased $10 million at their par value. In April 2002, we repurchased $20 million of the 2007 Notes at their discounted value for cash of $18.8 million plus accrued interest. A pre-tax gain of $0.9 million was recognized on these notes. Interest on the 2007 Notes is due May 1 and November 1 of each year. The indenture agreement provides for certain limitations on liens, additional indebtedness, certain investments and capital expenditures, dividends, mergers and sales of assets. At June 30, 2002, we were in compliance with all covenants of the indenture. In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan commercial bank, in the form of two loans, for construction of a 31-mile oil pipeline connecting the Tucupita Field production facility with the Uracoa central processing unit. The first loan, with an original principal amount of $6 million, bears interest payable monthly based on 90-day London Interbank Borrowing Rate ("LIBOR") plus 5 percent with principal payable quarterly for five years. The second loan, in the amount of 4.4 billion Venezuelan Bolivars ("Bolivars") (approximately $6.3 million), bears interest payable monthly based on a mutually agreed interest rate determined quarterly, or a six-bank average published by the central bank of Venezuela. The interest rate for the quarter ending June 30, 2002 was 58 percent with a negative effective interest rate taking into account exchange gains resulting from the devaluation of the Bolivar during the quarter. The loans provide for certain limitations on dividends, mergers and sale of assets. At June 30, 2001, we were in compliance with all covenants of the loans. In 2001, a dispute arose over collection by municipal taxing regimes on the Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit resulting in overpayments and underpayments to adjacent municipalities. As settlement, a portion of future municipal tax payments will be offset by the municipal tax that was originally overpaid. The present value of the long-term portion of the settlement liability is $0.7 million at December 31, 2001. The entire balance was repaid or reclassified to short-term by June 30, 2002. LIQUIDITY The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. We require capital principally to service out debt and to fund the following costs: o drilling and completion costs of wells and the cost of production, treating and transportation facilities; o geological, geophysical and seismic costs; and o acquisition of interests in oil and gas properties. The amount of available capital will affect the scope of our operations and the rate of our growth. As of June 30, 2002, our cash and marketable securities balances were $69.6 million. Our future rate of growth also depends substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to service our debt. Additionally, our ability to pay interest on our debt and general corporate overhead is partially dependent upon the ability of 11 Benton-Vinccler and Geoilbent to make loan repayments, dividends and other cash payments to us; however, there may be contractual obligations or legal impediments to receiving dividends or distributions from our subsidiaries. On April 12, 2002, we concluded the Arctic Gas Sale. The proceeds from the sale were used to redeem all $108.0 million senior unsecured notes due in 2003 plus $20.0 million senior unsecured notes due in 2007. Among the options under consideration for use of the remaining net proceeds are funding internally generated growth opportunities in Russia and Venezuela, further reductions of debt, purchasing shares of our stock or other corporate purposes. NOTE 4 - COMMITMENTS AND CONTINGENCIES In July 2001, we entered into a three-year lease for office space in Houston, Texas for approximately $11,000 per month. We also lease 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expires in December 2004. All of the California office space has been subleased for rents that approximate our lease costs. In October 2001, we received a letter from the New York Stock Exchange ("NYSE") notifying us that we had fallen below the continued listing standard of the NYSE. These standards include a total market capitalization of at least $50 million over a 30-day trading period and stockholders' equity of at least $50 million. According to the NYSE's notice, our total market capitalization over the 30 trading days ended October 17, 2001 was $48.2 million and our stockholders' equity was $16.0 million as of September 30, 2001. In accordance with the NYSE's rules, we submitted a plan to the NYSE in December 2001 detailing how we expected to reestablish compliance with the listing criteria within the next 18 months. In January 2002, the NYSE accepted our business plan, subject to quarterly reviews of the goals and objectives outlined in that plan. After the sale of our interest in Arctic Gas, the total market capitalization and stockholders equity deficiencies were eliminated. As of June 30, 2002, we were in compliance with the total market capitalization and stockholders' equity standards. On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the United States Bankruptcy Court, Western District of Louisiana against us and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy Corporation, of certain West Cote Blanche Bay properties for $15.1 million, constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550 of the Bankruptcy Code. In August 2001, a decision was rendered by the bankruptcy court in BOGLA's favor denying any and all relief to the WRT Trust and granting BOGLA its costs. WRT appealed the decision to the U.S. District Court for the Western District of Louisiana. Recently, the parties reached an agreement in principle to terminate the appeal and exchange mutual releases in return for a reduced payment ($27,500) to BOGLA of its court awarded costs. We expect the settlement to be concluded in the third quarter of 2002. In the normal course of our business, we may periodically become subject to actions threatened or brought by our investors or partners in connection with the operation or development of our properties or the sale of securities. We are also subject to ordinary litigation that is incidental to our business, none of which is expected to have a material adverse effect on our financial position, results of operations or liquidity. NOTE 5 - TAXES TAXES OTHER THAN ON INCOME Benton-Vinccler pays municipal taxes on operating fee revenues it receives for production from the South Monagas Unit. We have incurred the following Venezuelan municipal taxes and other taxes (in thousands): <Table> <Caption> THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, 2002 2001 2002 2001 -------- --------- --------- --------- Venezuelan Municipal Taxes $ 1,014 $ 1,659 $ 1,947 $ 2,520 Franchise Taxes 30 30 63 60 Payroll and Other Taxes 179 262 (203) 546 -------- --------- --------- --------- $ 1,223 $ 1,951 $ 1,807 $ 3,126 ======== ========= ========= ========= </Table> The six months ended June 30, 2002 included a non-recurring foreign payroll tax adjustment of $0.7 million. The six months ended June 30, 2001 include an adjustment to Venezuelan municipal taxes of $0.8 million due to a change in tax rates at the South Monagas Unit in Venezuela. TAXES ON INCOME At December 31, 2001, we had, for federal income tax purposes, operating loss carryforwards of approximately $130 million expiring in the years 2003 through 2020. It is anticipated that the entire $130 million will be utilized against the gain from Arctic Gas Sale. We will not provide deferred tax assets on future operating losses due to uncertainty of realization. We do not provide deferred income taxes on undistributed earnings of international consolidated subsidiaries for possible future remittances as all such earnings are reinvested as part of our ongoing business. 12 NOTE 6 - OPERATING SEGMENTS The Company regularly allocates resources to and assesses the performance of its operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Revenues from the Venezuela and United States operating segments are derived primarily from the production and sale of oil. Operations included under the heading "United States and other" include corporate management, exploration and production activities, cash management and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the United States and other segment and are not allocated to other operating segments. <Table> <Caption> THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, 2002 2001 2002 2001 ------------- --------------- ------------- ------------ OPERATING SEGMENT REVENUES Oil sales: Venezuela $ 33,022 $ 32,844 $ 60,269 $ 67,182 United States and other -- -- -- -- ------------- --------------- ------------- ------------ Total oil sales 33,022 32,844 60,269 67,182 ------------- --------------- ------------- ------------ OPERATING SEGMENT INCOME (LOSS) Venezuela 8,100 6,106 13,606 10,892 Russia (2,816) 749 (3,214) 2,905 United States and other 71,036 (8,017) 67,413 (12,674) ------------- --------------- ------------- ------------ Net income (loss) $ 76,320 $ (1,162) $ 77,805 $ 1,123 ============= =============== ============= ============ </Table> <Table> <Caption> JUNE 30, DECEMBER 31, 2002 2001 --------------- ---------------- OPERATING SEGMENT ASSETS Venezuela $ 184,231 $ 167,671 Russia 49,414 100,801 United States and other 154,350 165,254 --------------- ---------------- Subtotal 387,995 433,726 Intersegment eliminations (85,104) (85,575) --------------- ---------------- Total assets $ 302,891 $ 348,151 =============== ================ </Table> 13 NOTE 7 - RUSSIAN OPERATIONS GEOILBENT We own 34 percent of Geoilbent, a Russian limited liability company formed in 1991 that develops, produces and markets crude oil from the North Gubkinskoye and South Tarasovskoye Fields in the West Siberia region of Russia. Our investment in Geoilbent is accounted for using the equity method. Sales quantities attributable to Geoilbent for the six months ended March 31, 2002 and 2001 were 3,552,795 barrels and 2,477,110 barrels, respectively. Prices for crude oil for the six months ended March 31, 2002 and 2001 averaged $11.21 and $19.08 per barrel, respectively. Depletion expense attributable to Geoilbent for the six months ended March 31, 2002 and 2001 was $3.44 and $2.58 per barrel, respectively due to lower reserves. Financial information for Geoilbent follows (in thousands). All amounts represent 100 percent of Geoilbent. <Table> <Caption> STATEMENTS OF INCOME: THREE MONTHS ENDED SIX MONTHS ENDED MARCH 31, MARCH 31, -------------------------------- ----------------------------- 2002 2001 2002 2001 ---------- ---------- ----------- ----------- Revenues Oil sales $ 14,228 $ 19,685 $ 39,836 $ 47,304 ---------- ---------- ----------- ----------- 14,228 19,685 39,836 47,304 ---------- ---------- ----------- ----------- Expenses Selling and distribution expenses (a) 1,631 -- 3,908 -- Operating expenses 3,710 1,961 7,560 4,802 Depletion, depreciation and amortization 5,877 3,276 12,237 6,404 General and administrative 1,448 1,203 3,970 2,175 Taxes other than on income 5,724 5,717 12,730 14,793 ---------- ---------- ----------- ----------- 18,390 12,157 40,405 28,174 ---------- ---------- ----------- ----------- Income (loss) from operations (4,162) 7,528 (569) 19,130 Other Non-Operating Income (Expense) Other income 54 168 620 474 Interest expense (1,182) (1,949) (2,871) (3,972) Net gain on exchange rates 955 303 1,619 438 ---------- ---------- ----------- ----------- (173) (1,478) (632) (3,060) ---------- ---------- ----------- ----------- Income (loss) before income taxes (4,335) 6,050 (1,201) 16,070 Income tax expense 61 1,454 2,054 3,340 ---------- ---------- ----------- ----------- Net income (loss) $ (4,396) $ 4,596 $ (3,255) $ 12,730 ========== ========== =========== =========== </Table> (a) 2001 selling and distribution expenses were included in oil sales. <Table> <Caption> MARCH 31, SEPTEMBER 30, BALANCE SHEET DATA: 2002 2001 --------- ------------- Current Assets $ 20,646 $ 34,696 Other Assets 193,382 187,593 Current Liabilities 61,642 60,439 Other Liabilities 16,500 22,550 Net Equity 135,886 139,300 </Table> 14 The European Bank for Reconstruction and Development ("EBRD") and International Moscow Bank ("IMB") together agreed in 1996 to lend up to $65 million to Geoilbent, based on achieving certain reserve and production milestones, under parallel reserve-based loan agreements. In addition, the loan agreements require that Geoilbent meet certain financial ratios and covenants, including a minimum current ratio, and provides for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. Under these loan agreements, we and the other shareholder of Geoilbent have significant management and business support obligations. Each shareholder is jointly and severally liable to EBRD and IMB for any losses, damages, liabilities, costs, expenses and other amounts suffered or sustained arising out of any breach by any shareholder of its support obligations. Effective January 28, 2002, the interest rate for the loan was changed to six-month LIBOR plus 4.75 percent. Principal payments are due in varying installments on the semiannual interest payment dates beginning January 27, 2001 and ending by July 27, 2004. Geoilbent began borrowing under these facilities in October 1997 and had borrowed a total of $48.5 million through January 31, 2002. The proceeds from the loans were used by Geoilbent to develop the North Gubkinskoye Field. Geoilbent has repaid $18.5 million of the loan through March 31, 2002. The principal payment requirements for the long-term debt of Geoilbent at March 31, 2002 are as follows (in thousands): <Table> 2003 . . . . . . . . . . . . . . . . . . .$ 5,500 2004 . . . . . . . . . . . . . . . . . . . 11,000 ------- $16,500 </Table> On June 30, 2002, Geoilbent owed EBRD $27.5 million in total debt. Of this amount, $5.5 million was paid on July 29, 2002. On June 30, 2002 Geoilbent owed IMB $2.5 million in total debt. This amount was paid on July 29, 2002. In May 2001, Geoilbent obtained a $3.3 million loan from IMB payable in six payments of $0.6 million commencing August 1, 2001, ending November 1, 2002, bearing interest at LIBOR plus 6.5 percent. The loan is collateralized by moveable property in the South Tarasovskoye Field. On June 30, 2002, Geoilbent had $1.1 million outstanding with IMB under this loan. Of this amount, $0.4 million was paid in July 2002, $0.2 million was paid on August 1, 2002 and the balance is due in November 2002. At June 30, 2002, Geoilbent had accounts payable outstanding of $25.4 million of which approximately $8.5 million was 90 days or more past due. The amounts outstanding were primarily to contractors and vendors for drilling and construction services. Under Russian law, creditors, to whom payments are 90 days or more past due, can force a company into involuntary bankruptcy. As a minority shareholder in Geoilbent, we are attempting to cause Geoilbent and its majority shareholder to take the necessary steps to bring Geoilbent's payables current with such creditors. These steps have included a reduced capital expenditure budget. In June 2002, we loaned Geoilbent $2.5 million under a subordinated loan agreement. The loan bears interest at six month LIBOR until January 6, 2004, and the loan is due at that time. Payment is subordinated to the EBRD facility. Geoilbent also received an $5.0 million loan from the other shareholder. Proceeds from each loan were used to reduce accounts and taxes payable. There can be no assurance that Geoilbent will have the ability to repay the obligations when due. Involuntary bankruptcy would have no impact on cash flow, as Geoilbent has not paid a dividend. ARCTIC GAS COMPANY In April 1998, we signed an agreement to earn a 40 percent equity interest in Arctic Gas Company. Arctic Gas owns the exclusive rights to evaluate, develop and produce the natural gas, condensate and oil reserves in the Samburg and Yevo-Yakha license blocks in West Siberia. The two blocks comprise 794,972 acres within and adjacent to the Urengoy Field, Russia's largest producing natural gas field. Under the terms of a Cooperation Agreement between us and Arctic Gas, we earned a 40 percent equity interest in exchange for providing or arranging for a credit facility of up to $100 million for the project, the terms and timing of which were finalized in February 2002. We received voting shares representing a 40 percent ownership in Arctic Gas that contain restrictions on their sale and transfer. A Share Disposition Agreement provides for removal of the restrictions as disbursements are made under the credit facility. From December 1998 through December 2001, we purchased shares representing an additional 28 percent equity interest not subject to any sale or transfer restrictions. On April 12, 2002, we concluded the Arctic Gas Sale and transferred our 68% equity interest to the buyer. The equity earnings of Arctic Gas have historically been based on a calendar year ended September 30. The equity earnings for the first twelve days of April will be included in the results for the third quarter of 2002. 15 Arctic Gas began selling oil in June 2000. All amounts represent 100 percent of Arctic Gas. Summarized financial information for Arctic Gas follows (in thousands): <Table> <Caption> STATEMENTS OF OPERATIONS: THREE MONTHS ENDED MARCH 31, SIX MONTHS ENDED MARCH 31, ---------------------------------- -------------------------- 2002 2001 2002 2001 ------------ ------------- ---------- ---------- Oil sales $ 2,485 $ 1,424 $ 6,430 $ 3,441 ------------ ------------- ---------- ---------- 2,485 1,424 6,430 3,441 ------------ ------------- ---------- ---------- Expenses Selling and distribution expenses (a) 1,023 -- 2,588 -- Operating expenses 1,053 1,091 1,952 2,235 Depletion, depreciation and amortization 62 135 313 313 General and administrative 779 661 1,851 1,296 Taxes other than on income 587 835 1,133 1,773 ------------ ------------- ---------- ---------- 3,504 2,722 7,837 5,617 ------------ ------------- ---------- ---------- Loss from operations (1,019) (1,298) (1,407) (2,176) Other Non-Operating Income (Expense) Other expenses -- -- (5) -- Net gain (loss) on exchange rates (49) 1 (969) (282) Interest expense (634) (461) (82) (765) ------------ ------------- ---------- --------- (683) (460) (1,056) (1,047) ------------ ------------- ---------- --------- Loss before income taxes (1,702) (1,758) (2,463) (3,223) Income tax benefit -- -- -- (189) ------------ ------------- ---------- --------- Net loss $ (1,702) $ (1,758) $ (2,463) $ (3,034) ============ ============= ========== ========= </Table> (a) 2001 selling and distribution expenses were included in oil sales. <Table> <Caption> MARCH 31, SEPTEMBER 30, BALANCE SHEET DATA: 2002 2001 --------- ------------- Current assets $ 3,340 $ 1,205 Other assets 13,817 10,120 Current liabilities 33,758 23,955 Net deficit (16,601) (12,630) </Table> 16 NOTE 8 - VENEZUELA OPERATIONS On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then one of three exploration and production affiliates of the national oil company, Petroleos de Venezuela, S.A. ("PDVSA"). The operating service agreement covers the South Monagas Unit. Under the terms of the operating service agreement, Benton-Vinccler, a corporation owned 80 percent by us and 20 percent by Vinccler, is a contractor for PDVSA and is responsible for overall operations of the South Monagas Unit, including all necessary investments to reactivate and develop the fields comprising the South Monagas Unit. Benton-Vinccler receives an operating fee in U.S. dollars deposited into a U.S. commercial bank account for each barrel of crude oil produced (subject to periodic adjustments to reflect changes in a special energy index of the U.S. Consumer Price Index) and is reimbursed according to a prescribed formula in U.S. dollars for its capital costs, provided that such operating fee and cost recovery fee cannot exceed the maximum dollar amount per barrel set forth in the agreement. The Venezuelan government maintains full ownership of all hydrocarbons in the fields. The stability of government in Venezuela and the government's relationship with the state-owned national oil company, PDVSA, remain significant risks for our company. PDVSA is the sole purchaser of all Venezuela oil production. On April 11, 2002, the President of Venezuela was removed from power as a result of a civil and military coup. For a number of reasons, the interim government, initially installed by the military, failed and the past president regained power on April 13, 2002. Upon his return to power, the president named a new president of PDVSA who, in turn, reinstated certain key PDVSA executives whom the Venezuelan president had previously fired in February. These firings had contributed to the political instability in the government and were cause for concern for those companies doing business with PDVSA. During this period, our oil production was not interrupted. However, it did delay the importation of critical equipment, which contributed to the slowdown in our drilling operations. The importance of PDVSA to Venezuela's future is utmost. Accordingly, while no assurances can be given, we believe that PDVSA will continue to operate and to purchase our oil production, and that the government will work to minimize political uncertainty in order to continue to attract foreign capital investment. NOTE 9 - UNITED STATES OPERATIONS We have a 35 percent working interest in the Lakeside Exploration Prospect, Cameron Parish, Louisiana. One July 25, 2002, we spud the Claude Boudreaux #1 exploratory well on this prospect. In March 1997, we acquired a 40 percent participation interest in three California State offshore oil and gas leases ("California Leases") from Molino Energy Company, LLC ("Molino Energy"), which held 100 percent of these leases. The project area covers the Molino, Gaviota and Caliente Fields, located approximately 35 miles west of Santa Barbara, California. Because we had no firm approved plans to continue drilling on the California Leases and the 2199 #7 exploratory well did not result in commercial reserves, we wrote off all of the capitalized costs associated with the California Leases of $9.2 million and the joint interest receivable of $3.1 million due from Molino Energy at December 31, 1999. NOTE 10 - CHINA OPERATIONS In December 1996, we acquired Crestone Energy Corporation, a privately held company headquartered in Denver, Colorado, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation ("CNOOC") for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.0 million acres under certain circumstances, and lies within an area which is the subject of a territorial dispute between the People's Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with Conoco Inc. The dispute has lasted for many years, and there has been limited exploration and no development activity in the area under dispute. As part of our review of company assets, we conducted a third-party evaluation of the WAB-21 area. Through that evaluation and our own assessment it was determined because of the ongoing country dispute, and the inherent exploration, and development and marketing risks associated with this project required us to impair the undeveloped acreage by $13.4 million. The remaining $2.9 million represents the value of the block based on various assumptions and analgous public production profiles and plans. NOTE 11 - RELATED PARTY TRANSACTIONS From 1996 through 1998, we made unsecured loans to our then Chief Executive Officer, A. E. Benton, bearing interest at the rate of 6 percent per annum. We subsequently obtained a security interest in Mr. Benton's shares of our stock and stock options. In August 1999, Mr. Benton filed a chapter 11 (reorganization) bankruptcy petition in the U.S. Bankruptcy Court for the Central District of California, in Santa Barbara, California. In February 2000, we entered into a separation agreement with Mr. Benton pursuant to which we retained Mr. Benton under a consulting agreement to perform certain services for us. In addition, the consulting agreement provided Mr. Benton with incentive bonuses tied to our net cash receipts from the sale of our interests in Arctic Gas and Geoilbent. We paid Mr. Benton a total of $536,545 from February 2000 through May 2001 for services performed under the consulting agreement, and in June 2002, we made an estimated incentive bonus payment to Mr. Benton of $1.5 million in connection with the sale of our interest in Arctic Gas. On May 11, 2001, Mr. Benton and the Company entered into a settlement and release agreement under which the consulting agreement was terminated as to future services and Mr. Benton agreed to propose a plan of reorganization in his bankruptcy case that provides for the repayment of our loans to him. Through the settlement agreement we continue to retain our security interest in Mr. Benton's 600,000 shares of our stock and in his stock options, and we have the right to vote the shares owned by him and to direct the exercise of his options. Under the terms of the settlement agreement, repayment of our loans to Mr. Benton may be achieved through Mr. Benton's liquidation of certain assets, disposition of Mr. Benton's stock and stock options, and a portion of future income and any incentive bonuses paid under the consulting agreement. In March 2002, Mr. Benton filed a plan of reorganization in his bankruptcy case which incorporated the terms of the settlement agreement. On July 31, 2002, the bankruptcy court confirmed the plan of reorganization, and we expect the order to become final in August 2002. The amount of Mr. Benton's indebtedness to us currently approximates $6.7 million. We continue to accrue interest at the rate of 6 percent per annum and record additional allowances as the interest accrues. Based upon information provided by Mr. Benton's bankruptcy counsel, we anticipate that under the bankruptcy plan of reorganization we will receive a cash payment of about $1.7 million from the liquidation of assets. While we can provide no assurance, we believe that this cash payment, when coupled with the value of our stock, the stock options and other proceeds payable by Mr. Benton, will allow us to recover a significant portion of Mr. Benton's indebtedness to us. 17 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS We caution you that any forward-looking statements (as such term is defined in the Private Securities Litigation Reform Act of 1995) contained in this report or made by our management involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words budget, budgeted, anticipate, expect, believes, goals or projects and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the Private Securities Litigation Reform Act of 1995, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our substantial concentration of operations in Venezuela, the political and economic risks associated with international operations, the anticipated future development costs for our undeveloped proved reserves, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the operation and development of oil and gas properties and the drilling of oil and natural gas wells, the price for oil and natural gas, and other risks described in our filings with the Securities and Exchange Commission. The following factors, among others, may in some cases have affected our results and could cause actual results and plans for future periods to differ materially from those expressed or implied in any such forward-looking statements: fluctuations in oil and natural gas prices, changes in operating costs, overall economic conditions, political stability, acts of terrorism, currency and exchange risks, changes in existing or potential tariffs, duties or quotas, availability of additional exploration and development opportunities, availability of sufficient financing, changes in weather conditions, and ability to hire, retain and train management and personnel. A discussion of these factors is included in our 2001 Annual Report on Form 10-K, which includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS On April 12, 2002, we concluded the Arctic Gas Sale, on which we recognized a gain of $143.1 million ($92.9 million after tax) in the three months ended June 30, 2002. On March 31, 2002, we used part of the proceeds to retire the entire $108.0 million of 11.625 percent senior unsecured notes, and in April 2002, we purchased $20.0 million (face value) of 9.375 percent senior unsecured notes for $18.8 million plus accrued interest. A pre-tax gain of $0.9 million was recognized on the purchase of these notes. These redemptions reduced our annual interest expense by $14.5 million. Among the options under consideration for use of the remaining net proceeds are funding internally generated growth opportunities in Russia and Venezuela, further reductions of debt, purchasing shares of our stock or other corporate purposes. On May 14, 2002, the shareholders approved a change of our name to Harvest Natural Resources, Inc. On July 15, 2002, Kerry R. Brittain joined the company as our new Vice President, General Counsel and Corporate Secretary. Kerry brings over 24 years of extensive experience in corporate and oil and gas law, including serving as Vice President, General Counsel and Corporate Secretary for Union Pacific Resources Group Inc. prior to its merger with Anadarko Petroleum in 2000. We possess significant producing assets in Venezuela and Russia. We believe that the producing assets can be further optimized and the undeveloped acreage exploited for further development. Our growth strategy is to access large resources of hydrocarbons in Venezuela and Russia, to enable resource development, to manage risk and to harvest value. Current production from Geoilbent's North Gubkinskoye and South Tarasovskoye Fields is approximately 17,300 barrels of oil per day. We believe the wells drilled in the South Tarasovskoye Field in 2001 significantly increased the value of our Russian properties and we are reviewing alternatives to maximize their value. These alternatives include improved reservoir management, a computer simulation study of the field, improved drilling and completion practices, and construction of a natural gas processing facility. Geoilbent has entered into negotiations with EBRD to increase the amount of its loan commitment from the $22.0 million outstanding to a revolving facility of $50.0 million. EBRD has agreed in principal with the loan restructuring and the new loan documents should be signed sometime in the third quarter. It is expected that $8.0 million of the loan increase will be used to further reduce accounts and taxes payable and $20.0 million will be applied to an 85-well development program in the South Tarasovskoye Field. In addition to the EBRD restructuring, we are working with the majority shareholder to take the necessary steps to bring Geoilbent's payables current. These steps have included a reduction in the 2002 capital budget to approximately $16.6 million. In June, we loaned Geoilbent $2.5 million under a subordinated loan agreement. The loan bears interest at six-month LIBOR until January 6, 2004, and the loan is due at that time. Payment is subordinated to the EBRD facility. Geoilbent also received a $5.0 million loan from the other shareholder. Proceeds from each loan were used to reduce accounts and taxes payable. There can be no assurance that Geoilbent will have the ability to repay these obligations when due. Oil production from the Company's South Monagas Unit in Venezuela was virtually flat with last year's production at 2.5 million barrels (27,700 bopd) for the three months ended June 30, 2002. The Company is reducing its 2002 production guidance by 10 18 percent to 28,000 to 30,000 barrels of oil per day from the South Monagas Unit. The revised production profile is due to delays in the completion of additional water handling capacity at the Tucupita plant and in the Tucupita drilling program as a result of heavy rains. For the balance for the year, we will increase the South Monagas Unit capital expenditures program up to $11.4 million to approximately $42.5 million. We are evaluating the construction of additional processing and handling facilities and are in discussions with PDVSA to negotiate a gas sales contract that will allow for the first time sale of natural gas in Venezuela by our affiliate. RESULTS OF OPERATIONS We include the results of operations of Benton-Vinccler in our consolidated financial statements and reflect the 20 percent ownership interest of Vinccler as a minority interest. We account for our investments in Geoilbent and Arctic Gas using the equity method. We include Geoilbent and Arctic Gas in our consolidated financial statements based on a fiscal year ending September 30. Accordingly, our results of operations for the six months ended June 30, 2002 and 2001 reflect results from Geoilbent and Arctic Gas for the six months ended March 31, 2002 and 2001, respectively. We follow the full-cost method of accounting for our investments in oil and gas properties. We capitalize all acquisition, exploration, and development costs incurred. We account for our oil and gas properties using cost centers on a country by country basis. We credit proceeds from sales of oil and gas properties to the full-cost pools if the sales do not result in a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved property. We amortize capitalized costs of oil and gas properties within the cost centers on an overall unit-of-production method using proved oil and gas reserves as audited or prepared by independent petroleum engineers. Costs that we amortize include: o all capitalized costs (less accumulated amortization and impairment); o the estimated future expenditures (based on current costs) to be incurred in developing proved reserves; and o estimated dismantlement, restoration and abandonment costs (see Note 1 of the "Notes to the Consolidated Financial Statements" for additional information). You should read the following discussion of the results of operations for the three and six months ended June 30, 2002 and 2001 and the financial condition as of June 30, 2002 and December 31, 2001 in conjunction with our Consolidated Financial Statements and related Notes thereto included in PART I, Item 1, "Financial Statements." THREE MONTHS ENDED JUNE 30, 2002 AND 2001 Our revenues increased $0.2 million, or 1 percent, during the three months ended June 30, 2002 compared with 2001. This was due to increased oil sales revenue in Venezuela as a result of increased sales quantities, partially offset by decreases in world crude oil prices. Our sales quantities for the three months ended June 30, 2002 from Venezuela were 2.5 million barrels (27,100 barrels of oil per day) compared with 2.4 million barrels (26,400 barrels of oil per day) for the three months ended June 30, 2001. The increase in sales quantities of 69,000 barrels, or 3 percent, was due primarily to our Tucupita drilling program. Prices for crude oil averaged $13.37 per barrel (pursuant to terms of an operating service agreement) from Venezuela during the three months ended June 30, 2002 compared with $13.68 per barrel during the three months ended June 30, 2001. Our operating expenses decreased $1.2 million, or 14 percent, during the three months ended June 30, 2002 compared with the three months ended June 30, 2001. This was primarily due to reduced transportation costs, workovers and the devaluation of Bolivar based expenditures at the South Monagas Unit in Venezuela. Operating expenses during the three months ended June 30, 2002 compared with the same period of 2001 were $3.42 per barrel and $4.02 per barrel, respectively. We anticipate that operating expenses at the South Monagas Unit will average between $3.00 and $3.50 per barrel in 2002. Depletion, depreciation and amortization increased $0.5 million, or 7 percent, during the three months ended June 30, 2002 compared with 2001 primarily due to increased oil production, decreased proved reserves and increased future development costs at the South Monagas Unit. Depletion expense per barrel of oil produced from Venezuela during the three months ended June 30, 2002 was $2.37 compared with $2.12 during 2001. We recognized write-downs of $13.4 million and $0.4 million at June 30, 2002 and 2001, respectively, for the impairment of the China WAB-21 block in the three months ended June 30, 2002 as well as of capitalized costs associated with exploration prospects in both periods. Total general and administrative expenses decreased $0.4 million, or 7 percent, during the three months ended June 30, 2002 as compared with 2001. Increases in general and administrative expenses in the three months ended June 30, 2002 were for performance bonuses ($1.1 million), legal and insurance costs ($0.4 million), severance and stock option vesting acceleration ($0.6 million), and other miscellaneous expenses ($0.2 million). These increases are less than the general and administrative expenses incurred in the three months ended June 30, 2001 for the reduction in force ($1.2 million), underwriting fees to amend indenture covenants ($1.1 million), and the inability to capitalize exploration overhead and reduced office rent ($0.4 million). 19 Taxes other than on income decreased $0.7 million, or 60 percent, during the three months ended June 30, 2002 compared with the three months ended June 30, 2001. Investment income and other increased $0.3 million, or 23 percent, during the three months ended June 30, 2002 compared with 2001, primarily due to lower interest rates on higher marketable securities balances due to the Arctic Gas Sale. Interest expense decreased $1.7 million, or 37 percent, during the three months ended June 30, 2002 compared with 2001. This was primarily due to the redemption of the 2003 senior unsecured notes and the purchase of $20 million 2007 senior unsecured notes. Net gain on exchange rates increased $2.2 million for the three months ended June 30, 2002 compared with 2001 due to changes in the value of the Bolivar and increased net monetary liabilities denominated in Bolivars. We realized income before income taxes and minority interest of $140.2 million during the three months ended June 30, 2002 compared with income of $3.2 million in 2001. This resulted in increased income tax expense of $55.8 million. The effective tax rate of 43 percent varies from the U.S. statutory rate of 35 percent primarily as a result of an increase in the valuation allowance for net operating losses generated in 2002 that are not expected to be realized in the future, adjustments to the prior year estimated net operating loss, and the tax effect of the write-off of the China WAB-21 block, for which there is no expected tax benefit. The income attributable to the minority interest increased $0.5 million for the three months ended June 30, 2002 compared with 2001. This was primarily due to the increased profitability of Benton-Vinccler. Equity in net earnings of affiliated companies decreased $3.2 million during the three months ended June 30, 2002 compared with 2001. This was primarily due to the increased loss from Geoilbent and Arctic Gas. Our share of revenues from Geoilbent was $4.8 million for the three months ended March 31, 2002 compared with revenues of $6.7 million for 2001. The decrease of $1.9 million, or 38 percent, was due to lower world crude oil prices partially offset by increased sales quantities. Prices for Geoilbent's crude oil averaged $8.68 per barrel during the three months ended March 31, 2002 compared with $16.42 per barrel for the three months ended March 31, 2001. Our share of Geoilbent oil sales quantities increased by 149,643 barrels, or 27 percent, from 557,302 barrels sold during the three months ended March 31, 2002 to 407,659 barrels sold during the three months ended March 31, 2001. SIX MONTHS ENDED JUNE 30, 2002 AND 2001 Our revenues decreased $6.9 million, or 11 percent, during the six months ended June 30, 2002 compared with 2001. This was due to decreased oil sales revenue in Venezuela as a result of a decrease in world crude oil prices. Our sales quantities for the six months ended June 30, 2002 from Venezuela were 5.0 million barrels (27,500 barrels of oil per day) compared with 5.0 million barrels for the six months ended June 30, 2001. Normal volume declines in existing wells were offset by new production under the Tucupita Field development. Prices for crude oil averaged $12.03 per barrel (pursuant to terms of an operating service agreement) from Venezuela during the six months ended June 30, 2002 compared with $13.51 per barrel during the six months ended June 30, 2001. Our operating expenses decreased $6.7 million, or 42 percent, during the six months ended June 30, 2002 compared with the six months ended June 30, 2001. This was primarily due to decreased workover costs and the devaluation of Bolivar based expenditures. Operating expenses during the six months ended June 30, 2002 compared with the same period of 2001 were $3.17 per barrel and $4.52 per barrel, respectively. Depletion, depreciation and amortization increased $2.1 million, or 14 percent, during the six months ended June 30, 2002 compared with 2001 primarily due to increased oil production, decreased proved reserves and increased future development costs at the South Monagas Unit. Depletion expense per barrel of oil produced from Venezuela during the six months ended June 30, 2002 was $2.37 compared with $2.12 during 2001. We recognized write-downs of $13.4 million and $0.4 million at June 30, 2002 and 2001, respectively, for the impairment of the China WAB-21 block in the three months ended June 30, 2002 as well as of capitalized costs associated with exploration prospects in both periods. General and administrative expenses decreased $1.8 million, or 21 percent, during the six months ended June 30, 2002 compared with 2001. Increases in general and administrative expenses in the six months ended June 30, 2002 were for performance bonuses ($1.1 million), legal and insurance costs ($0.6 million), and other miscellaneous expenses ($0.4 million). These increases are less than the general and administrative expenses incurred in the six months ended June 30, 2001 for severance and stock option vesting acceleration ($0.3 million), the reduction in force ($1.9 million), underwriting fees to amend indenture covenants ($1.1 million), inability to capitalize exploration overhead, and reduced office rent and sublease income ($0.6 million). Taxes other than on income decreased $1.3 million, or 73 percent, during the six months ended June 30, 2002 compared with the six months ended June 30, 2001 primarily due to one-time municipal tax adjustments due to a change in tax rates at the South Monagas Unit in Venezuela. Investment income and other decreased slightly, during the six months ended June 30, 2002 compared with 2001, primarily due to lower average interest rates and higher marketable securities balances due to the Arctic Gas Sale. Interest expense decreased $1.3 million, or 12 percent, during the six months ended June 30, 2002 compared with 2001. This was primarily due to redemption of the 2003 senior unsecured notes and the purchase of $20 million 2007 senior unsecured notes. Net gain on exchange rates increased $4.2 million for the six months ended June 30, 2002 compared with 2001. This was due to changes in the value of the Bolivar and increased net monetary liabilities denominated in Bolivars. We realized income before income taxes 20 and minority interests of $144.8 million during the six months ended June 30, 2002 compared with income of $7.6 million in 2001. This resulted in increased income tax expense of $54.4 million. The effective tax rate of 43 percent varies from the U.S. statutory rate of 35 percent primarily as a result of an increase in the valuation allowance for net operating losses generated in 2002 that are not expected to be realized in the future, adjustments to the prior year estimated net operating loss, and the tax effect of the write-off of the China WAB-21 block, for which there is no expected tax benefit. The income attributable to the minority interest increased $0.6 million for the six months ended June 30, 2002 compared with 2001. This was primarily due to the increased profitability of Benton-Vinccler. Equity in net earnings of affiliated companies decreased $5.6 million during the six months ended June 30, 2002 compared with 2001. This was primarily due to the increased losses from Geoilbent and Arctic Gas. Our share of revenues from Geoilbent was $13.5 million for the six months ended March 31, 2002 compared with revenues of $16.1 million for 2001. The decrease of $2.5 million, or 19 percent, was due to significantly lower Russian domestic crude oil prices partially offset by increased sales quantities. Prices for Geoilbent's crude oil averaged $11.21 per barrel during the six months ended March 31, 2002 compared with $19.08 per barrel for the six months ended March 31, 2001. Our share of Geoilbent oil sales quantities increased by 365,053 barrels, or 30 percent, from 1,207,950 barrels sold during the six months ended March 31, 2002 to 842,897 barrels sold during the six months ended March 31, 2001. NEW ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact of SFAS No. 143 and therefore, at this time, cannot reasonably estimate the effect of this statement on its consolidated financial position, results of operations or cash flows. In May 2002, the FASB issued SFAS No. 145, Recission of FASB Statements No. 44, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS 145 rescinds the automatic treatment of gains or losses from extinguishment of debt as extraordinary items as outlined in APB Opinion No. 30, "Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions". As allowed under the provisions of SFAS 145, we had decided to early adopt SFAS 145 (See Note 3). In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. SFAS 146 replaces Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)". CAPITAL RESOURCES AND LIQUIDITY The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. We require capital principally to service our debt and to fund the following costs: o drilling and completion costs of wells and the cost of production and transportation facilities; o geological, geophysical and seismic costs; and o acquisition of interests in oil and gas properties. The amount of available capital will affect the scope of our operations and the rate of our growth. As of June 30, 2002, our cash and marketable securities balance was $69.6 million. Our future rate of growth also depends substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to service our debt. Additionally, our ability to pay interest on our debt and general corporate overhead is dependent upon the ability of Benton-Vinccler and Geoilbent to make loan repayments, dividend and other cash payments to us; however, there may be contractual obligations or legal impediments to receiving dividends or distributions from our subsidiaries. Debt Reduction and Restructuring Program. We currently have significant debt principal obligations payable in 2007 ($85 million). We may pursue additional open market debt purchases of the obligations due in 2007 to further reduce the debt. 21 Working Capital. Our capital resources and liquidity are affected by the timing of our semiannual interest payments of approximately $4.0 million each May 1 and November 1 and by the quarterly payments from PDVSA at the end of the months of February, May, August and November pursuant to the terms of the contract between Benton-Vinccler and PDVSA. As a consequence of the timing of these interest payment outflows and the PDVSA payment inflows, our cash balances can increase and decrease dramatically on a few dates during the year. In each May and November in particular, interest payments at the beginning of the month and PDVSA payments at the end of the month create large swings in our cash balances. We have an uncommitted short-term working capital facility of 13 billion Bolivars, (approximately $10 million at June 30, 2002), available to Benton-Vinccler by a Venezuelan commercial bank. The credit facility bears interest at fixed rates for 30-day periods, is guaranteed by us and contains no restrictive or financial ratio covenants. We believe that similar arrangements will be available to us in future quarters. At June 30, 2002, there was no outstanding balance. In February 2002, the Venezuelan Bolivar was allowed to float against the U.S. dollar, resulting in a significant devaluation of the Bolivar. While the long-term impact of this action is uncertain, the short-term implication may be difficulty in purchasing U.S. dollars with Bolivars and reducing U.S. dollar equivalent amounts of Benton-Vinccler's short-term working capital facility. We are negotiating with a bank to replace the short-term working capital facility with a $15 million project financing to fund certain infrastructure improvements. We do not expect this action to have a material impact on Benton-Vinccler's operations. Among the options under consideration for use of the remaining net proceeds are funding internally generated growth opportunities in Russia and Venezuela, further reductions of debt, purchasing shares of our stock or other corporate purposes. We continue to develop sources of additional capital and management of our cash requirements by various techniques including, but not limited to: o managing the scope and timing of our capital expenditures, substantially all of which are within our discretion; o forming joint ventures or alliances with financial or other industry partners; o possible future hedging price risks and; o monetizing assets. The net funds raised or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below: <Table> <Caption> SIX MONTHS ENDED JUNE 30, -------------------------- 2002 2001 --------- -------- Net cash provided by operating activities $ 11,887 $ 23,983 Net cash provided by (used in) investing activities 164,947 (16,774) Net cash provided by (used in) financing activities (129,149) 5,988 --------- -------- Net increase in cash $ 47,685 $ 13,197 ========= ======== </Table> At June 30, 2002, we had current assets of $111.9 million and current liabilities of $46.7 million, resulting in working capital of $65.2 million and a current ratio of 2.4 to 1. This compares with a negative working capital of $0.6 million and a negative current ratio at December 31, 2001. The increase in working capital of $65.8 million was primarily due to the Arctic Gas Sale. At June 30, 2002, Geoilbent had accounts payable outstanding of $25.4 million of which approximately $8.5 million was 90 days or more past due. The amounts outstanding were primarily to contractors and vendors for drilling and construction services. Under Russian law, creditors, for which payments are 90 days or more past due, can force a company into involuntary bankruptcy. As a minority shareholder in Geoilbent, we are attempting to cause Geoilbent and its majority shareholder to take the necessary steps to bring Geoilbent's payables current with such creditors. These steps have included a reduced capital expenditure budget. In June 2002, we loaned Geoilbent $2.5 million under a subordinated loan agreement. The loan bears interest at six-month LIBOR until January 6, 2004, and the loan is due at that time. Payment is subordinated to the EBRD facility. Geoilbent also received an additional $5.0 million from a loan from the other shareholder. Proceeds from each loan were used to reduce accounts and taxes payable. There can be no assurance that Geoilbent will have the ability to repay its obligations when due. Involuntary bankruptcy would have no impact on cash flow, as Geoilbent has not paid a dividend. Cash Flow from Operating Activities. During the six months ended June 30, 2002 and 2001, net cash provided by operating activities was approximately $11.9 million and $24.0 million, respectively. Cash flow from operating activities decreased by $12.1 million during the six months ended June 30, 2002 compared with 2001. This was primarily due to increased collections of accrued revenues and reduced interest payments which were substantially offset by a reduction in accounts payable, restructuring charges of $0.9 million associated with the reduction in force and corporate restructuring plan adopted in June 2001 and legal and professional fees of $1.0 million associated with the offer to restructure our senior notes due May 1, 2003. 22 Cash Flow from Investing Activities. A $189.8 million payment was received on the Arctic Gas Sale. During the six months ended June 30, 2002 and 2001, we had drilling and production related capital expenditures of approximately $20.7 million and $22.2 million, respectively, related to the South Monagas Unit. We expect capital expenditures of approximately $42.5 million for calendar year 2002, including the $11.4 million revision substantially all of which will be at the South Monagas Unit. The timing and size of the investments for the South Monagas Unit is substantially at our discretion. We anticipate that Geoilbent will continue to fund its expenditures through its own cash flow, the $7.5 million loans from its shareholders, and credit facilities. Our remaining capital commitments worldwide are relatively minimal and are substantially at our discretion. We will also be required to make interest payments of approximately $8 million related to our outstanding senior notes during the next 12 months. Cash Flow from Financing Activities. In November 1997, we issued $115 million in 9.375 percent senior unsecured notes due November 1, 2007, of which we subsequently repurchased $30 million for cash. Interest on all of the notes is due May 1 and November 1 of each year. The indenture agreement provides for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. At June 30, 2002, we were in compliance with all covenants of the indenture. In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan commercial bank, in the form of two loans, for construction of a 31-mile oil pipeline that will connect the Tucupita Field production facility with the Uracoa central processing unit. The first loan, in the amount of $6 million, bears interest payable monthly based on 90-day LIBOR plus 5 percent (7.04 percent at June 30, 2002) with principal payable quarterly for five years. The second loan, in the amount of 4.4 billion Venezuelan Bolivars (approximately $6.3 million), bears interest payable monthly based on a mutually agreed interest rate determined quarterly or a 6-bank average published by the central bank of Venezuela. The Bolivar interest rate at June 30, 2002 was 58 percent or a negative percent in U.S. dollar terms for the quarter due to the Bolivar devaluation. DOMESTIC OPERATIONS One July 25, 2002, we spud the Claude Boudreaux #1 exploratory well on this prospect. We have a 35 percent working interest in the Lakeside Exploration Prospect, Cameron Parish, Louisiana. In March 1997, we acquired a 40 percent participation interest in three California State offshore oil and natural gas leases ("California Leases") from Molino Energy Company, LLC ("Molino Energy"), which held 100 percent of these leases. The project area covers the Molino, Gaviota and Caliente Fields, located approximately 35 miles west of Santa Barbara, California. Because we had no firm approved plans to continue drilling on the California Leases and the 2199 #7 exploratory well did not result in commercial reserves, we wrote off all of the capitalized costs associated with the California Leases of $9.2 million and the joint interest receivable of $3.1 million due from Molino Energy at December 31, 1999. INTERNATIONAL OPERATIONS On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with an affiliate of the national oil company, Petroleos de Venezuela, S.A. ("PDVSA"). The operating service agreement covers the South Monagas Unit. Under the terms of the operating service agreement, Benton-Vinccler, a corporation owned 80 percent by us and 20 percent by Vinccler, is a contractor for PDVSA and is responsible for overall operations of the Unit South Monagas, including all necessary investments to reactivate and develop the fields comprising the South Monagas Unit. The Venezuelan government maintains full ownership of all hydrocarbons in the fields. In December 1996, we acquired Crestone Energy Corporation, a privately held company headquartered in Denver, Colorado, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation ("CNOOC") for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.0 million acres under certain circumstances, and lies within an area which is the subject of a territorial dispute between the People's Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with Conoco Inc. The dispute has lasted for many years, and there has been limited exploration and no development activity in the area under dispute. As part of our review of company assets, we conducted a third-party evaluation of the WAB-21 area. Through that evaluation, and our own assessment, it was determined, because of the ongoing country dispute, and the inherent exploration, and development marketing risks associated with this project required us to impair the undeveloped acreage by $13.4 million. The remaining $2.9 million represents the value of the block based on various assumptions and analogous public production profiles and plans. 23 On April 12, 2002, we completed the Arctic Gas Sale. The equity earnings of Arctic Gas have historically been based on a calendar year ended September 30. The equity earnings for the first twelve days of April will be included in the third calendar quarter of 2002. This amount is not expected to be material. In December 1991, the joint venture agreement forming Geoilbent was registered with the Ministry of Finance of the USSR. Geoilbent's ownership is as follows: o Harvest owns 34 percent; o Open Joint Stock Company Minley ("Minley") owns 66 percent. In November 1993, the agreement was registered with the Russian Agency for International Cooperation and Development. Geoilbent was later re-chartered as a limited liability company. We believe that we have developed a good relationship with the other Geoilbent shareholder and have not experienced any disagreements on major operational matters. We are reviewing ways to improve the operations, but we are a minority partner. Geoilbent shareholder action requires a 67 percent majority vote of its shareholders. Geoilbent develops, produces and markets crude oil from the North Gubinskoye and South Tarasovskoye Fields in the West Siberia region of Russia, located approximately 2,000 miles northeast of Moscow. Large proven oil and gas fields surround all four of Geoilbent's licenses. The North Gubinskoye field is included inside a license block of 167,086 acres, an area approximately 15 miles long and four miles wide. The field has been delineated with over 60 exploratory wells, which tested 26 separate reservoirs. The field is a large anticlinal structure with multiple pay sands. The development to date has focused on the BP 8, 9, 10, 11 and 12 reservoirs with minor development in the BP 6 and 7 reservoirs. Geoilbent is currently flaring the produced natural gas in accordance with environmental regulations, although it is exploring alternatives to market the natural gas. The South Tarasovskoye Field is located a few miles southeast of North Gubinskoye field and straddles the eastern boundary of the Urabor Yakhinsky exploration block acquired by Geoilbent in 1998. It is estimated a majority of the field is situated within the block. The remaining portion of the field falls within a license block owned by Purneftegaz. Production began in early 2001 from a discovery well drilled close to the boundary by Purneftegaz. Only 521 of Geoilbent's 763,558 acres in this field are reflected as proved-developed acres. Geoilbent also holds rights to two more license blocks comprising 426,199 acres. The Russian government sets the maximum crude oil export tariff rate as a percentage of the customs dollar value of Urals, Russia's main crude export blend. Under the current system when the Urals price is in a range of $109.50 to $182.50 per ton ($15.00 to $25.00 per barrel), a tariff of 35 percent is imposed on the sum exceeding the level of $109.50. When Urals crude is below $109.50 per ton, no tariff is collected. When the price rises above $182.50 per ton, exporters pay a combined tariff comprising $25.48 per ton, plus a tariff of 40 percent on the sum exceeding $182.50. We are unable to predict the impact of taxes, duties and other burdens for the future on our Russian operations. The Russian government will again raise the export tariff beginning August 1, 2002 to $21.90 per ton ($3.00 per barrel) due to the rise in oil prices over the last several months. EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION Our results of operations and cash flow are affected by changing oil prices. However, our South Monagas Unit oil sales are based on a fee adjusted quarterly by the percentage change of a basket of crude oil prices instead of by absolute dollar changes. This dampens both any upward and downward effects of changing prices on our Venezuelan oil sales and cash flows. If the price of oil increases, there could be an increase in our cost for drilling and related services because of increased demand, as well as an increase in oil sales. Fluctuations in oil and natural gas prices may affect our total planned development activities and capital expenditure program. There are presently no restrictions in either Venezuela or Russia that restrict converting U.S. dollars into local currency. However, from June 1994 through April 1996, Venezuela implemented exchange controls which significantly limited the ability to convert local currency into U.S. dollars. Because payments to Benton-Vinccler are made in U.S. dollars into its United States bank account, and Benton-Vinccler is not subject to regulations requiring the conversion or repatriation of those dollars back into Venezuela, the exchange controls did not have a material adverse effect on us or Benton-Vinccler. Currently, there are no exchange controls in Venezuela or Russia that restrict conversion of local currency into U.S. dollars for routine business operations, such as the payments of invoices, debt obligations and dividends. Within the United States, inflation has had a minimal effect on us, but it is potentially an important factor in results of operations in Venezuela and Russia. With respect to Benton-Vinccler and Geoilbent, a significant majority of the sources of funds, including the proceeds from oil sales, our contributions and credit financings, are denominated in U.S. dollars, while local transactions in Russia and Venezuela are conducted in local currency. If the rate of increase in the value of the dollar compared 24 to the bolivar continues to be less than the rate of inflation in Venezuela, then inflation could be expected to have an adverse effect on Benton-Vinccler. During the six months ended June 30, 2002, net foreign exchange gains attributable to our Venezuelan operations were $4.4 million and net foreign exchange gains attributable to our Russian operations were $0.7 million. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, many of which are beyond our control. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan and Russian currencies to the U.S. dollar. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls. Our operations are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by price controls, tax and other laws relating to the petroleum industry, by changes in such laws and by changing administrative regulations and the interpretations and application of such rules and regulations. In addition, various federal, state, local and international laws and regulations covering the discharge of materials into the environment, the disposal of oil and natural gas wastes, or otherwise relating to the protection of the environment, may affect our operations and results. CONCLUSION While we can give you no assurance, we currently believe that our capital resources and liquidity will be adequate to fund our planned capital expenditures, investments in and advances to affiliates, and semiannual interest payment obligations for the next 12 months. Our expectation is based upon cash and marketable securities on hand and our current estimate of projected price levels, production and the availability of short-term working capital facilities of up to $10 million during the time periods between the submission of quarterly invoices to PDVSA by Benton-Vinccler and the subsequent payments of these invoices by PDVSA. Actual results could be materially affected if there is a significant decrease in either price or production levels related to the South Monagas Unit. Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well as various economic conditions that have historically affected the oil and natural gas business. Prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond our control. We estimate that a change in the price of oil of $1.00 per barrel would affect cash flow from operations by approximately $1.2 million based on our second quarter production rates and cost structure. 25 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to market risk from adverse changes in oil and natural gas prices, interest rates and foreign exchange, as discussed below. OIL AND NATURAL GAS PRICES As an independent oil and natural gas producer, our revenue, other income and equity earnings and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and condensate. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Historically, prices received for oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. This volatility is demonstrated by the average realizations in Venezuela, which declined from $10.01 per barrel in 1997 to $6.75 in 1998, increased to $14.94 in 2000, decreased to $12.52 in 2001 and averaged $12.03 in the first six months of 2002. Based on our budgeted production and costs, we will require an average realization in Venezuela of approximately $8.64 per barrel in 2002 in order to break-even on income from consolidated companies before our equity in earnings from affiliated companies. From time to time, we have utilized hedging transactions with respect to a portion of our oil and natural gas production to achieve a more predictable cash flow, as well as to reduce our exposure to price fluctuations, but we have utilized no such transactions since 1996. While hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. Because gains or losses associated with hedging transactions are included in oil sales when the hedged production is delivered, such gains and losses are generally offset by similar changes in the realized prices of the commodities. We did not enter into any commodity hedging agreements during the six months ended June 30, 2002 or 2001. INTEREST RATES Total long-term debt at June 30, 2002 of $90.2 million consisted of fixed-rate senior unsecured notes maturing in 2007 ($85.3 million) and $4.9 million of floating-rate notes due in 2006. A hypothetical 10 percent adverse change in the floating rate would not have had a material affect on our results of operations for the six months ended June 30, 2002. FOREIGN EXCHANGE Our operations are located primarily outside of the United States. In particular, our current oil producing operations are located in Venezuela and Russia, countries which have had recent histories of significant inflation and devaluation. For the Venezuelan operations, oil sales are received under a contract in effect through 2012 in U.S. dollars; expenditures are both in U.S. dollars and local currency. For the Russian operations, a majority of the oil sales are received in Rubles; expenditures are both in U.S. dollars and local currency, although a larger percentage of the expenditures are in local currency. We have utilized no currency hedging programs to mitigate any risks associated with operations in these countries, and therefore our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in these countries. POLITICAL RISK The stability of government in Venezuela and the government's relationship with the state-owned national oil company, PDVSA, remain significant risks for our company. PDVSA is the sole purchaser of all Venezuela oil production. On April 11, 2002, the President of Venezuela was removed from power as a result of a civil and military coup. For a number of reasons, the interim government, initially installed by the military, failed and the past president regained power on April 13, 2002. Upon his return to power, the president named a new president of PDVSA who, in turn, reinstated certain key PDVSA executives who in the Venezuelan president had previously fired in February. These firings had contributed to the political instability in the government and were cause for concern for those companies doing business with PDVSA. During this period, our oil production was not interrupted. However, it did delay the importation of critical equipment which contributed to the slowdown in our drilling operations. The importance of PDVSA to Venezuela's future is utmost. PDVSA supplies 50 percent of all government revenues, 33 percent of Gross Domestic Product and 75 percent of total exports. Accordingly, while no assurances can be given, we believe that PDVSA will continue to operate and to purchase our oil production, and that the government will work to minimize political uncertainty in order to continue to attract foreign capital investment. 26 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS WRT Litigation On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the United States Bankruptcy Court, Western District of Louisiana against us and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy Corporation, of certain West Cote Blanche Bay properties for $15.1 million, constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550 of the Bankruptcy Code. In August 2001, a decision was rendered by the bankruptcy court in BOGLA's favor denying any and all relief to the WRT Trust and granting BOGLA its costs. WRT appealed the decision to the U.S. District Court for the Western District of Louisiana. Recently, the parties reached an agreement in principle to terminate the appeal and exchange mutual releases in return for a reduced payment ($27,500) to BOGLA of its court awarded costs. We expect the settlement to be concluded in the third quarter of 2002. A. E. Benton Reorganization From 1996 through 1998, we made unsecured loans to our then Chief Executive Officer, A. E. Benton, bearing interest at the rate of 6 percent per annum. We subsequently obtained a security interest in Mr. Benton's shares of our stock and stock options. In August 1999, Mr. Benton filed a chapter 11 (reorganization) bankruptcy petition in the U.S. Bankruptcy Court for the Central District of California, in Santa Barbara, California. In February 2000, we entered into a separation agreement with Mr. Benton pursuant to which we retained Mr. Benton under a consulting agreement to perform certain services for us. In addition, the consulting agreement provided Mr. Benton with incentive bonuses tied to our net cash receipts from the sale of our interests in Arctic Gas and Geoilbent. We paid Mr. Benton a total of $536,545 from February 2000 through May 2001 for services performed under the consulting agreement, and in June 2002, we made an estimated incentive bonus payment to Mr. Benton of $1.5 million in connection with the sale of our interest in Arctic Gas. On May 11, 2001, Mr. Benton and the Company entered into a settlement and release agreement under which the consulting agreement was terminated as to future services and Mr. Benton agreed to propose a plan of reorganization in his bankruptcy case that provides for the repayment of our loans to him. Through the settlement agreement we continue to retain our security interest in Mr. Benton's 600,000 shares of our stock and in his stock options, and we have the right to vote the shares owned by him and to direct the exercise of his options. Under the terms of the settlement agreement, repayment of our loans to Mr. Benton may be achieved through Mr. Benton's liquidation of certain assets, disposition of Mr. Benton's stock and stock options, and a portion of future income and any incentive bonuses paid under the consulting agreement. In March 2002, Mr. Benton filed a plan of reorganization in his bankruptcy case which incorporated the terms of the settlement agreement. On July 31, 2002, the bankruptcy court confirmed the plan of reorganization, and we expect the order to become final in August 2002. The amount of Mr. Benton's indebtedness to us currently approximates $6.7 million. We continue to accrue interest at the rate of 6 percent per annum and record additional allowances as the interest accrues. Based upon information provided by Mr. Benton's bankruptcy counsel, we anticipate that under the bankruptcy plan of reorganization we will receive a cash payment of about $1.7 million from the liquidation of assets. While we can provide no assurance, we believe that this cash payment, when coupled with the value of our stock, the stock options and other proceeds payable by Mr. Benton, will allow us to recover a significant portion of Mr. Benton's indebtedness to us. ITEM 2. CHANGES IN SECURITIES None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. 27 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS At our Annual Meeting of Stockholders held on May 14, 2002, the following items were voted on by the Stockholders: 1. To approve the Election of Directors: <Table> <Caption> Votes in Favor Votes Against/Withheld -------------- ---------------------- Stephen D. Chesebro' 30,782,740 491,481 John U. Clarke 30,528,573 745,648 H. H. Hardee 30,540,517 733,704 Peter J. Hill 30,822,168 452,053 Patrick M. Murry 30,562,667 711,554 </Table> 2. To ratify the appointment of PricewaterhouseCoopers LLP as the independent accountants for the year ended December 31, 2002: <Table> <Caption> Votes in Favor Votes Against/Withheld Abstentions/Broker Non-Votes -------------- ---------------------- ---------------------------- 30,786,747 422,345 65,129 </Table> 3. To approve the Amended and Restated Certificate of Incorporation to incorporate previously adopted amendments and to change the name of the company to "Harvest Natural Resources, Inc.": <Table> <Caption> Votes in Favor Votes Against/Withheld Abstentions/Broker Non-Votes -------------- ---------------------- ---------------------------- 30,616,824 524,182 133,215 </Table> ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 3.1(i) Amended and Restated Certificate of Incorporation of Benton Oil and Gas Company. 3.1(ii) Restated Bylaws as of May 14, 2002. 4.1 Rights Agreement between Benton Oil and Gas Company and First Interstate Bank, Rights Agent dated April 28, 1995. 10.2 Subordinated Loan Agreement US$2,500,000 between Limited Liability Company "Geoilbent" as borrower, and Harvest Natural Resources, Inc. as lender. 10.3 See 4.1 above. (b) Reports on Form 8-K One April 9, 2002, we filed a report on the sale of our interest in Arctic Gas Company on Form 8-K under Item 2, "Acquisition or Disposition of Assets", and Item 7(b), "Financial Statements and Exhibits - Pro Forma Financial Information". 28 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. HARVEST NATURAL RESOURCES, INC. Dated: August 13, 2002 By: /s/Peter J. Hill ---------------- Peter J. Hill President and Chief Executive Officer Dated: August 13, 2002 By: /s/Steven W. Tholen ------------------- Steven W. Tholen Senior Vice President of Finance and Administration and Chief Financial Officer 29 ACCOMPANYING CERTIFICATE PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 Not Filed Pursuant to the Securities Exchange Act of 1934 The undersigned Chief Executive Officer and Chief Financial Officer of Harvest Natural Resources, Inc. (the "Company") do hereby certify as follows: Solely for the purpose of meeting the apparent requirements of Section 906 of the Sarbanes-Oxley Act of 2002, and solely to the extent this certification may be applicable to this Quarterly Report on Form 10-Q, the undersigned hereby certify that this Quarterly Report on Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in this Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: August 13, 2002 By: /s/ Peter J. Hill ----------------- Peter J. Hill President and Chief Executive Officer Dated: August 13, 2002 By: /s/ Steven W. Tholen -------------------- Steven W. Tholen Senior Vice President of Finance and Administration and Chief Financial Officer EXHIBIT INDEX <Table> <Caption> Exhibit No. Description ------- ----------- 3.1(i) Amended and Restated Certificate of Incorporation of Benton Oil and Gas Company. 3.1(ii) Restated Bylaws as of May 14, 2002. 4.1 Rights Agreement between Benton Oil and Gas Company and First Interstate Bank, Rights Agent dated April 28, 1995. 10.2 Subordinated Loan Agreement US$2,500,000 between Limited Liability Company "Geoilbent" as borrower, and Harvest Natural Resources, Inc. as lender. 10.3 See 4.1 above. </Table>