10-Q 1 l90792ae10-q.txt BENTON OIL AND GAS COMPANY FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) Quarterly Report Pursuant to Section 13 or 15(d) [X] of the Securities Exchange Act of 1934 For the Quarterly Period Ended September 30, 2001 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 BENTON OIL AND GAS COMPANY (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 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 November 12, 2001, 33,946,919 shares of the Registrant's Common Stock were outstanding. 2 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
Page ---- PART I FINANCIAL INFORMATION Item 1. FINANCIAL STATEMENTS Consolidated Balance Sheets at September 30, 2001 and December 31, 2000 (Unaudited)........................................................3 Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2001 and 2000 (Unaudited).....................................4 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2001 and 2000 (Unaudited).....................................5 Notes to Consolidated Financial Statements......................................................6 Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS..............................................................22 Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.......................................34 PART II OTHER INFORMATION Item 1. LEGAL PROCEEDINGS................................................................................36 Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS........................................................36 Item 3. DEFAULTS UPON SENIOR SECURITIES..................................................................36 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............................................36 Item 5. OTHER INFORMATION................................................................................36 Item 6. EXHIBITS AND REPORTS ON FORM 8-K.................................................................36 SIGNATURES...............................................................................................................37
3 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, unaudited)
SEPTEMBER 30, DECEMBER 31, 2001 2000 ------------------ ----------------- ASSETS ------ CURRENT ASSETS: Cash and cash equivalents $ 18,461 $ 15,132 Restricted cash 12 12 Marketable securities - 1,303 Accounts and notes receivable: Accrued oil revenue 30,590 38,003 Joint interest and other, net 9,740 6,778 Prepaid expenses and other 1,562 2,404 ------------ ------------ TOTAL CURRENT ASSETS 60,365 63,632 RESTRICTED CASH 16 10,920 OTHER ASSETS 5,059 5,891 DEFERRED INCOME TAXES 4,827 4,293 INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES 99,373 77,741 PROPERTY AND EQUIPMENT: Oil and gas properties (full cost method - costs of $17,935 and $16,634 excluded from amortization in 2001 and 2000, respectively) 524,659 490,548 Furniture and fixtures 10,519 11,049 ------------ ------------ 535,178 501,597 Accumulated depletion, impairment and depreciation (395,677) (377,627) ------------ ------------ 139,501 123,970 ------------ ------------ $ 309,141 $ 286,447 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------ CURRENT LIABILITIES: Accounts payable, trade and other $ 4,198 $ 12,804 Accrued expenses 30,428 25,797 Accrued interest payable 9,480 3,733 Income taxes payable 10,200 3,214 Short-term borrowings - 5,714 Current portion of long-term debt 2,457 - ------------ ------------ TOTAL CURRENT LIABILITIES 56,763 51,262 LONG-TERM DEBT 221,598 213,000 OTHER LIABILITIES 1,138 - COMMITMENTS AND CONTINGENCIES MINORITY INTEREST 13,638 9,281 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 33,947 shares at September 30, 2001 and 33,872 shares at December 31, 2000 339 339 Additional paid-in capital 156,874 156,629 Accumulated deficit (140,510) (143,365) Treasury stock, at cost, 50 shares (699) (699) ------------ ------------ TOTAL STOCKHOLDERS' EQUITY 16,004 12,904 ------------ ------------ $ 309,141 $ 286,447 ============ ============
See accompanying notes to consolidated financial statements. 4 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data, unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------ ------------------------------- 2001 2000 2001 2000 ------------- ------------ ------------- ------------ REVENUES Oil and natural gas sales $ 31,370 $ 37,972 $ 98,552 $ 101,516 ----------- ---------- ----------- ----------- 31,370 37,972 98,552 101,516 ----------- ---------- ----------- ----------- EXPENSES Operating expenses 9,683 12,983 32,188 34,767 Depletion, depreciation and amortization 5,963 4,141 18,668 11,654 Write-downs of oil and gas properties and impairments - - 411 1,069 General and administrative 5,456 3,782 15,876 12,324 Taxes other than on income 1,243 1,364 4,369 3,460 ----------- ---------- ----------- ----------- 22,345 22,270 71,512 63,274 ----------- ---------- ----------- ----------- INCOME FROM OPERATIONS 9,025 15,702 27,040 38,242 OTHER NON-OPERATING INCOME (EXPENSE) Investment income and other 710 2,234 2,373 6,562 Interest expense (6,126) (7,318) (18,464) (22,228) Net gain on exchange rates 297 67 516 200 ----------- ---------- ----------- ----------- (5,119) (5,017) (15,575) (15,466) ----------- ---------- ----------- ----------- INCOME FROM CONSOLIDATED COMPANIES BEFORE INCOME TAXES AND MINORITY INTERESTS 3,906 10,685 11,465 22,776 INCOME TAX EXPENSE 3,510 5,018 10,587 13,309 ----------- ---------- ----------- ----------- INCOME BEFORE MINORITY INTERESTS 396 5,667 878 9,467 MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY COMPANIES 1,523 2,007 4,357 4,978 ----------- ---------- ----------- ----------- INCOME (LOSS) FROM CONSOLIDATED COMPANIES (1,127) 3,660 (3,479) 4,489 EQUITY IN NET EARNINGS OF AFFILIATED COMPANIES 2,859 2,213 6,334 4,117 ----------- ---------- ----------- ----------- INCOME BEFORE EXTRAORDINARY INCOME 1,732 5,873 2,855 8,606 EXTRAORDINARY INCOME ON DEBT REPURCHASE, NET OF TAX OF $0 - 3,095 - 3,095 ----------- ---------- ----------- ----------- NET INCOME $ 1,732 $ 8,968 $ 2,855 $ 11,701 =========== ========== =========== =========== NET INCOME PER COMMON SHARE: Basic: Income before extraordinary income $ 0.05 $ 0.19 $ 0.08 $ 0.29 Extraordinary income - 0.10 - 0.10 ----------- ---------- ----------- ----------- Net income $ 0.05 $ 0.29 $ 0.08 $ 0.39 =========== ========== =========== =========== Diluted: Income before extraordinary income $ 0.05 $ 0.19 $ 0.08 $ 0.29 Extraordinary income - 0.10 - 0.10 ----------- ---------- ----------- ----------- Net income $ 0.05 $ 0.29 $ 0.08 $ 0.39 =========== ========== =========== ===========
See accompanying notes to consolidated financial statements. 5 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands, unaudited)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2001 2000 -------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 2,855 $ 11,701 Adjustments to reconcile net income to net cash provided by operating activities: 18,668 11,654 Depletion, depreciation and amortization 411 1,069 Write-downs of oil and gas properties and impairments 944 1,047 Amortization of financing costs Loss on disposal of assets -- 20 Equity in earnings of affiliated companies (6,334) (4,117) Allowance for employee notes and accounts receivable 247 247 Non-cash compensation-related charges 245 -- 4,357 4,978 Minority interest in undistributed earnings of subsidiaries Extraordinary income from repurchase of debt -- (3,095) (534) 36 Deferred income taxes Changes in operating assets and liabilities: Accounts and notes receivable 4,204 (8,754) Prepaid expenses and other 842 1,010 Accounts payable (8,606) 8,042 Accrued expenses 4,631 7,711 Accrued interest payable 5,747 5,012 Income taxes payable 6,986 10,014 NET CASH PROVIDED BY OPERATING ACTIVITIES 34,663 46,575 -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions of property and equipment (34,610) (40,127) Investment in and advances to affiliated companies (15,298) (7,091) Increase in restricted cash (57) (199) Decrease in restricted cash 10,961 1,225 Purchase of marketable securities (15,067) (13,650) Maturities of marketable securities 16,370 16,052 -------- -------- NET CASH USED IN INVESTING ACTIVITIES (37,701) (43,790) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from exercise of stock options -- 260 Proceeds from issuance of short-term borrowings and notes payable 21,111 -- Payments on short-term borrowings and notes payable (14,632) (3,539) (Increase) decrease in other assets (112) 463 -------- -------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 6,367 (2,816) -------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3,329 (31) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 15,132 21,147 -------- -------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 18,461 $ 21,116 ======== ======== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION $ 13,512 $ 14,749 Cash paid during the period for interest expense ======== ======== Cash paid during the period for income taxes $ 1,711 $ 1,559 ======== ========
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES During the nine months ended September 30, 2000, we repurchased $8 million face value of our senior unsecured notes with the issuance of 2,710,590 shares of common stock. See accompanying notes to consolidated financial statements. 6 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NINE MONTHS ENDED SEPTEMBER 30, 2001 (UNAUDITED) NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION We engage in the exploration, development, production and management of oil and gas properties. We conduct our business principally in Venezuela and Russia. 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 over 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). 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 September 30, 2001, and the results of operations for the three and nine month periods ended September 30, 2001 and 2000 and cash flows for the nine month periods ended September 30, 2001 and 2000. 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, 2000, for additional disclosures, including a summary of our accounting policies. The results of operations for the three and nine month periods ended September 30, 2001 are not necessarily indicative of the results to be expected for the full year. USE OF ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. ACCOUNTS AND NOTES RECEIVABLE Allowance for doubtful accounts related to employee notes was $6.4 million and $6.2 million at September 30, 2001 and December 31, 2000, respectively (see Note 11). Allowance for doubtful accounts related to joint interest and other accounts receivable was $0.3 million at December 31, 2000. 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 notes. 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 $1.3 million of commercial paper at December 31, 2000. 7 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 nine month periods ended September 30, 2001 or September 30, 2000 and, in accordance with SFAS 130, have not provided a separate statement of comprehensive income. NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141, "Business Combinations," SFAS 142 "Goodwill and Other Intangible Assets" and SFAS 143 "Accounting for Asset Retirement Obligations." SFAS 141 eliminates the pooling method of accounting for a business combination, except for qualifying business combinations that were initiated prior to July 1, 2001, and requires that all combinations be accounted for using the purchase method. SFAS 142, which is effective for fiscal years beginning after December 15, 2001, addresses accounting for identifiable intangible assets, eliminates the amortization of goodwill and provides specific steps for testing the impairment of goodwill. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives. SFAS 143, which is effective for fiscal years beginning after June 15, 2002, requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred as a capitalized cost of the long-lived asset and to depreciate it over its useful life. We are currently in the process of evaluating the impact that SFAS 142 and SFAS 143 will have on our financial position and results of operations. In October 2001, the FASB issued SFAS 144, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121 and the accounting and reporting provisions of APB Opinion No. 30. SFAS 144 is effective for fiscal years beginning after December 15, 2001. We are currently in the process of evaluating the impact that SFAS 144 will have on our financial position and results of operations. EARNINGS PER SHARE In February 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 128 ("SFAS 128") "Earnings per Share." SFAS 128 replaces the presentation of primary earnings per share with a presentation of basic earnings per share based upon the weighted average number of common shares for the period. It also requires dual presentation of basic and diluted earnings per share for companies with complex capital structures. The numerator (income), denominator (shares) and amount of the basic and diluted earnings per share computations for income were (in thousands, except per share amounts):
AMOUNT PER INCOME SHARES SHARE ------------- ------------ ------------ FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001 --------------------------------------------- BASIC EPS Income attributable to common stockholders $ 1,732 33,947 $ 0.05 ======== ========= ======== Effect of dilutive securities: Stock options and warrants - 3 -------- --------- DILUTED EPS Income attributable to common stockholders $ 1,732 33,950 $ 0.05 ======== ========= ======== FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000 BASIC EPS Income attributable to common stockholders $ 5,873 30,339 $ 0.19 ======== ========= ======== Effect of dilutive securities: Stock options and warrants - 192 -------- --------- DILUTED EPS Income attributable to common stockholders $ 5,873 30,531 $ 0.19 ======== ========= ========
8
AMOUNT PER INCOME SHARES SHARE ------------- ------------ ------------ FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001 -------------------------------------------- BASIC EPS Income attributable to common stockholders $ 2,855 33,945 $ 0.08 ======== ======== ======== Effect of dilutive securities: Stock options and warrants - 68 -------- -------- DILUTED EPS Income attributable to common stockholders 2,855 34,013 $ 0.08 ======== ======== ======== FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 -------------------------------------------- BASIC EPS Income attributable to common stockholders $ 8,606 29,865 $0.29 ======== ======== ======== Effect of dilutive securities: Stock options and warrants - 243 -------- -------- DILUTED EPS Income attributable to common stockholders $ 8,606 30,108 $0.29 ======== ======== ========
An aggregate of 7.8 million and 5.6 million shares that may be issued on the exercise of options and warrants were excluded from the earnings per share calculations because the exercise price exceeded the average share price during the three month periods ended September 30, 2001 and 2000, respectively. An aggregate of 6.7 million and 5.7 million shares that may be issued on the exercise of options and warrants were excluded from the earnings per share calculations because the exercise price exceeded the average share price during the nine month periods ended September 30, 2001 and 2000, 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 $0.6 million and $0.4 million for the nine months ended September 30, 2001 and 2000, respectively, and capitalized interest of $0.7 million and $0.4 million for the nine months ended September 30, 2001 and 2000, 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 $17.9 million and $16.6 million at September 30, 2001 and December 31, 2000, 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. Substantially all of the excluded costs at September 30, 2001 and December 31, 2000 relate to the acquisition of Benton Offshore China Company and evaluation related to its Wan `An Bei property. The remaining excluded costs of $0.9 million are expected to be included in amortizable costs during the next two to three years. The ultimate timing of when the costs related to the acquisition of Benton Offshore China Company will be included in amortizable costs is uncertain. 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 nine months ended September 30, 2001 and 2000, was $15.6 million and $10.2 million ($2.12 and $1.48 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 $3.0 million and $1.3 million for the nine months ended September 30, 2001 and 2000, respectively. Additionally, as a result of the reduction in force and corporate restructuring discussed below, the value of unamortized leasehold improvements has been reduced by $1.4 million for the anticipated loss on subleasing our former corporate headquarters and the carrying value of fixed assets has been reduced by $0.4 million. 9 REDUCTION IN FORCE AND CORPORATE RESTRUCTURING In June 2001, we implemented a plan designed to reduce general and administrative costs, including exploration overhead, at our corporate headquarters and to transfer geological and geophysical activities to our overseas offices in Maturin, Venezuela and in Western Siberia and Moscow, Russia. The reduction in general and administrative costs is being accomplished by reducing our headquarters staff and relocating our headquarters to Houston, Texas from Carpinteria, California. In June 2001, we recorded restructuring charges of $2.1 million, $0.9 million of which are included in general and administrative expenses and $1.2 million of which are included in depletion, depreciation and amortization. The restructuring charges included $0.9 million for severance and termination benefits for 27 employees, $0.8 million for the anticipated loss on subleasing the former Carpinteria, California headquarters and $0.4 million for the reduction in the carrying value of fixed assets that were not transferred to Houston. In September 2001, we recorded additional restructuring charges of $1.4 million related to the Carpinteria, California building lease due to changes in the local commercial building lease market, $0.8 million of which are included in general and administrative expenses and $0.5 million of which are included in depletion, depreciation and amortization. The implementation of the plan was substantially complete by the end of the third quarter of 2001. From June through September 2001, 21 employees were terminated and $0.7 million in severance payments were paid. As of September 30, 2001, the accrued expenses associated with the reduction in force and corporate restructuring plan, including anticipated costs to terminate the building lease of the former Carpinteria, California headquarters office of $0.8 million, were $1.0 million. The accrued expenses are expected to be paid by the end of the first quarter of 2002. RECLASSIFICATIONS Certain items in 2000 have been reclassified to conform to the 2001 financial statement presentation. 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. Equity in earnings of Geoilbent and Arctic Gas are based on a fiscal year ending September 30. No dividends have been paid to the Company 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):
GEOILBENT, LTD. ARCTIC GAS COMPANY TOTAL ------------------------ ------------------------- ------------------------ SEP 30, DEC 31, SEP 30, DEC 31, SEP 30, DEC 31, 2001 2000 2001 2000 2001 2000 ---------- ---------- ----------- ---------- ---------- ---------- Investments Equity in net assets $ 28,056 $ 28,056 $(2,558) $(2,218) $ 25,498 $ 25,838 Other costs, net of amortization (103) (202) 28,127 19,058 28,024 18,856 ---------- ---------- ----------- ---------- ---------- ---------- Total investments 27,953 27,854 25,569 16,840 53,522 44,694 Advances - - 28,466 21,986 28,466 21,986 Equity in earnings (losses) 19,134 12,310 (1,749) (1,249) 17,385 11,061 ---------- ---------- ----------- ---------- ---------- ---------- Total $ 47,087 $ 40,164 $ 52,286 $ 37,577 $ 99,373 $ 77,741 ========== ========== =========== ========== ========== ==========
10 NOTE 3 - LONG-TERM DEBT AND LIQUIDITY LONG-TERM DEBT Long-term debt consists of the following (in thousands):
SEPTEMBER 30, DECEMBER 31, 2001 2000 ---------------- ---------------- Senior unsecured notes with interest at 9.375%. See description below. $ 105,000 $ 105,000 Senior unsecured notes with interest at 11.625%. See description below. 108,000 108,000 Note payable with interest at 8.7%. See description below. 5,400 - Note payable with interest at 21%. See description below. 5,655 - ---------------- ---------------- 224,055 213,000 Less current portion 2,457 - ---------------- ---------------- $ 221,598 $ 213,000 ================ ================
In November 1997, we issued $115 million in 9.375 percent senior unsecured notes due November 1, 2007 ("2007 Notes"), of which we subsequently repurchased $10 million at their par value. In May 1996, we issued $125 million in 11.625 percent senior unsecured notes due May 1, 2003 ("2003 Notes"), of which we repurchased $17 million at their discounted value in September 2000 and November 2000 with the issuance of 4.2 million common shares with a market value of $9.3 million and cash of $3.5 million plus accrued interest. Interest on the notes is due May 1 and November 1 of each year. The indenture agreements provide for certain limitations on liens, additional indebtedness, certain investments and capital expenditures, dividends, mergers and sales of assets. In August 2001, we received the requisite consents from the holders of the 2003 Notes and 2007 Notes to amend the indentures governing the notes and the supplemental indentures have become operative. The amendments enable Arctic Gas Company to incur non-recourse debt of up to $77 million to fund its oil and gas development program. At September 30, 2001, we were in compliance with all covenants of the indentures. 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, with an original principal amount of $6 million, bears interest payable monthly based on 90-day LIBOR plus 5 percent 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 six-bank average published by the central bank of Venezuela. The interest rate for the quarter ending September 2001 was 21 percent with an effective interest rate of 7.8 percent taking into account exchange rate gains resulting from devaluation of the Bolivar during the quarter. Principal on the second loan is payable quarterly for five years beginning in September 2001. The loans provide for certain limitations on dividends, mergers and sale of assets. At September 30, 2001, we were in compliance with all covenants of the loans. LIQUIDITY As a result of our substantial leverage and disappointing financial results prior to 2000, our equity and public debt values have eroded significantly. In order to effectuate the changes necessary to restore our financial flexibility and to enhance our ability to execute a viable strategic plan, we began undertaking several significant actions in 2000, including: - hiring a new President and Chief Executive Officer, a new Senior Vice President and Chief Financial Officer and a new Vice President and General Counsel; - reconstituting our Board of Directors with industry executives with proven experience in oil and natural gas operations, finance and international operations; - redefining our strategic priorities to focus on value creation; - initiating capital conservation steps and financial transactions, including the repurchase of some of our outstanding senior notes, designed to de-leverage the Company and improve our cash flow for reinvestment; - undertaking a comprehensive study of our core Venezuelan asset to attempt to enhance the value of its production to ultimately increase cash flow and potentially extend its productive life; 11 - pursuing means to accelerate the commercial development of our Russian assets; - seeking relief from certain restrictive provisions of our debt instruments; and - implementing a plan designed to reduce general and administrative costs at our corporate headquarters by $3 to 4 million, or approximately 50 percent, and to transfer geological and geophysical activities to our overseas offices. We continue to aggressively explore means by which to maximize stockholder value. We believe that we possess significant producing properties in Venezuela which have yet to be optimized and valuable unexploited acreage in Venezuela and Russia. In fact, we believe the seven new wells drilled in the South Tarasovskoye Field since July 2001 significantly increase the value of our Russian properties and we are reviewing alternatives to maximize their value. These alternatives include accelerating the Russian development program and the potential sale of all or part of the Russian assets. However, the intrinsic value of our assets is burdened by a heavy debt load and constraints on capital to further exploit such opportunities. Therefore, we, with the advice of our financial and legal advisers, after having conducted a comprehensive review to consider our strategic alternatives, initiated a process in May 2001 intended to effectively extend the maturity of the senior notes due May 1, 2003 by exchanging new 13.125 percent senior notes due December 2007 plus warrants to purchase shares of our common stock for each of the 2003 Notes. While we believe the terms of the exchange offer made to the holders of the 2003 Notes were in the best interest of the noteholders and other Benton stakeholders, the majority of the noteholders would not exchange their notes for notes of a longer maturity on economic terms which were acceptable to us. As a result, the exchange offer was withdrawn in July 2001. In August 2001, we solicited and received the requisite consents from the holders of both the 2003 Notes and the 2007 Notes to amend certain covenants in the indentures governing the notes to enable Arctic Gas Company to incur nonrecourse debt of up to $77 million to fund its oil and gas development program. As an incentive to consent, we offered to pay each noteholder an amount in cash equal to $2.50 per $1,000 principal amount of notes held for which executed consents were received. The total amount of consent fees paid to the consenting noteholders was $0.3 million, which has been included in general and administrative expenses. Additionally, we have implemented a plan designed to reduce general and administrative costs at our corporate headquarters and to transfer geological and geophysical activities to our overseas offices in Maturin, Venezuela and in Western Siberia and Moscow, Russia. We continue to evaluate other strategic alternatives including, but not limited to, selling all or part of our existing assets in Venezuela and Russia, or the sale of the Company. However, no assurance can be given that any of these steps can be successfully completed or that we ultimately will determine that any of these steps should be taken. As a result of the decline in oil prices, in 1999 we instituted a capital expenditure program to reduce expenditures to those that we believed were necessary to maintain current producing properties. In the second half of 1999, oil prices recovered substantially. In December 1999, we entered into incentive-based development alliance agreements with Schlumberger and Helmerich & Payne as part of our plans to resume development of the South Monagas Unit in Venezuela (see Note 8). During 2000, we drilled 26 new oil wells and re-entered 2 oil wells in the Uracoa Field under the alliance agreements utilizing Schlumberger's technical and engineering resources. In January 2001, we suspended the development drilling program until the second half of 2001 in order to thoroughly review all aspects of operations and to integrate field performance to date with revised computer simulation modeling and improved well completion technology. In August 2001, drilling re-commenced in the Uracoa Field under the alliance agreement with Schlumberger. We anticipate drilling a total of eight new wells in Uracoa and then six to ten wells in the Tucupita Field commencing in late 2001 or early 2002. In August 2001, Benton-Vinccler signed an agreement to amend the alliance with Schlumberger. The amended long-term incentive-based alliance continues to provide incentives intended to improve initial production rates of new wells and to increase the average life of the downhole pumps at South Monagas. In addition, Schlumberger has agreed to provide drilling and completion services for new wells utilizing fixed lump-sum pricing. We chose not to renew the alliance with Helmerich & Payne and have entered into a standard drilling contract with Flint South America, Inc. ("Flint"). In September 2001, we completed the reservoir simulation study of the Uracoa Field and expect to complete a revised field development plan, incorporating the results of this study, in the early part of 2002. While no assurance can be given, we currently believe that we have sufficient flexibility with our discretionary capital expenditures and investments in and advances to affiliates that our capital resources and liquidity will be adequate to fund our semiannual interest payment obligations for the next 12 months. This expectation is based upon our current estimate of projected price levels, production and the availability of short-term working capital facilities of up to $11 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 are significant additional decreases in crude oil prices or decreases in 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 $0.8 million based on our third quarter production rates and cost structure. 12 In October 2000, an uncommitted short-term working capital facility of 8 billion Bolivars (approximately $11 million) was made 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. In January 2001, Benton-Vinccler borrowed 5.4 billion Bolivars (approximately $7.7 million) under this facility, which it repaid in February 2001. Again in October 2001, we borrowed 5 billion Bolivars (approximately $6.7 million) under the facility which will be repaid in November 2001 after the receipt of the third quarter payment from PDVSA. At September 30, 2001, the facility had no outstanding balance. We have significant debt principal obligations payable in 2003 and 2007. During September 2000, we exchanged 2.7 million shares of our common stock, plus accrued interest, for $8 million face value of our 11.625 percent senior notes due in 2003 and purchased $5 million face value of our 2003 senior notes for cash of $3.5 million plus accrued interest. Additionally, in November 2000, we exchanged 1.5 million shares of our common stock, plus accrued interest, for an aggregate $4 million face value of our 11.625 percent senior notes due in 2003. We may exchange additional common stock or cash for senior notes at a substantial discount to their face value if available on economic terms and subject to certain limitations. Under the rules of the New York Stock Exchange, the common stockholders would need to approve the issuance of an aggregate of more than 5.9 million shares of common stock in exchange for senior notes. The effect on existing stockholders of further issuances in excess of 5.9 million shares of common stock in exchange for senior notes will be to materially dilute the existing stockholders if material portions of the senior notes are exchanged. The dilutive effect on the common stockholders would depend upon a number of factors, the primary ones being the number of shares issued, the price at which the common stock is issued and the discount on the senior notes exchanged. If our future cash requirements are greater than our financial resources, we intend to develop sources of additional capital and/or reduce our cash requirements by various techniques including, but not limited to, the pursuit of one or more of the following alternatives: restructure the existing debt; reduce the total debt outstanding by exchanging debt for equity or by repaying debt with proceeds from the sale of assets, each on appropriate terms; manage the scope and timing of our capital expenditures, substantially all of which are within our discretion; form joint ventures or alliances with financial or other industry partners; sell all or a portion of our existing assets, including interests in our assets; issue debt or equity securities or otherwise raise additional funds or, merge or combine with another entity or sell the Company. There can be no assurance that any of the alternatives, or some combination thereof, will be available or, if available, will be on terms acceptable to us. NOTE 4 - COMMITMENTS AND CONTINGENCIES On February 17, 1998, the WRT Creditors Liquidation Trust ("WRT 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 (the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was insolvent at the time of its acquisition of the properties and that it paid a price in excess of the fair value of the property. A trial commenced on May 1, 2000 that concluded at the end of August 2000, and post trial briefs were filed. In August 2001, a favorable decision was rendered in BOGLA's favor denying any and all relief to the WRT Trust. The WRT Trust has stated that it would appeal the decision prior to the end of 2001; however, we believe that any such appeal would result in an outcome consistent with the court's prior decision. In May 1996, we entered into an agreement with Morgan Guaranty that provided for an $18 million cash collateralized five-year letter of credit to secure our performance of the minimum exploration work program required on the Delta Centro Block in Venezuela. As a result of expenditures made related to the exploration work program, the letter of credit had been reduced to $7.7 million. In January 2001, we and our bidding partners reached an agreement to terminate the remainder of the exploration work program in exchange for the unused portion of the standby letter of credit of $7.7 million. In March 2001, Benton-Vinccler submitted a claim to PDVSA for approximately $16 million seeking recovery for the value of oil quality adjustments made by PDVSA to the oil delivered by Benton-Vinccler since production began at the South Monagas Unit in 1993. We believe that we have a contractual basis for the claim as the oil quality adjustments are not in conformity with the delivery specifications set out in the operating service agreement. PDVSA has agreed to research and reconstruct their computer records from date of first delivery in order to research the claim. Any compensation from PDVSA related to this matter will be recorded in the period in which PDVSA confirms our claim. Benton-Vinccler produces natural gas associated with the production of oil in the South Monagas Unit. A portion of the natural gas is consumed as fuel for field operations and the remaining natural gas is re-injected. Benton-Vinccler has been in 13 discussions with PDVSA for several years regarding the appropriate amount to pay PDVSA for the natural gas consumed as fuel and has, to date, recorded a liability based on rates previously charged by PDVSA. It is uncertain when a final agreement regarding the payment for natural gas consumed as fuel will be reached or if the amounts accrued will reflect the ultimate settlement of the obligation. 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 these matters are currently expected to have a material adverse effect on our financial position, results of operations or liquidity. We have employment contracts with three senior management personnel which provide for annual base salaries, bonus compensation and various benefits. The contracts provide for the continuation of salary and benefits for the respective terms of the agreements in the event of termination of employment without cause. These agreements expire at various times from December 31, 2002 to July 9, 2003. We have entered into equity acquisition agreements in Russia which call for us to provide or arrange for certain amounts of credit financing in order to remove sale and transfer restrictions on the equity acquired or to maintain ownership in such equity (see Note 7). We lease office space in Carpinteria, California under two long-term lease agreements that are subject to annual rent adjustments based on certain changes in the Consumer Price Index. We lease 17,500 square feet of space in a building that we no longer occupy under a lease agreement that expires in December 2004; all of this office space has been subleased for rents that approximate our lease costs. Additionally, we lease 51,000 square feet of space in a building formerly used as our headquarters office in Carpinteria, California, for approximately $79,000 per month under a lease agreement that expires in August 2013. We have subleased 31,000 square feet of office space in this building for approximately $51,000 per month. We are currently evaluating terminating the building lease and estimate the cost to do so will be approximately $0.8 million. In July 2001, we entered into a three-year lease agreement for 8,600 square feet of office space in a building in Houston, Texas for approximately $11,000 per month. We recently received a letter from the New York Stock Exchange ("NYSE") notifying us that we have fallen below the continued listing standards 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 as of June 30, 2001, was $14.3 million ($16 million at September 30, 2001). In accordance with the NYSE's rules, we intend to submit a plan to the NYSE by mid-December detailing how we expect to reestablish compliance with the listing criteria within the next 18 months. The NYSE is expected to respond to the plan within 45 days after it is submitted. Because of our ongoing efforts to implement our strategic plan for improvements and to evaluate alternatives to restore our financial flexibility, we believe that we will be able to meet the NYSE's continued listing standards in the future. These alternatives include continued cost reductions, production enhancements, selling all or part of our assets in Venezuela and/or Russia, restructuring the debt or some combination of these alternatives. We may also recommend selling the Company. However, we cannot give any assurance that any of these steps can be successfully completed or that we ultimately will determine that any of these steps should be taken. Failure to meet the NYSE criteria may result in the delisting of our common stock on the NYSE. As a result, an investor may find it more difficult to dispose or obtain quotations or market value of our common stock, which may adversely affect the marketability of our common stock. However, given our strategic plan referenced above, we are optimistic that we will be able to meet the NYSE requirements in the future and consequently, do not expect our stock to be delisted. 14 NOTE 5 - TAXES TAXES OTHER THAN ON INCOME Benton-Vinccler pays municipal taxes of approximately 3.6 percent of 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):
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, 2001 2000 2001 2000 ----------- ----------- ----------- ------------ Venezuelan municipal taxes $ 1,015 $ 817 $ 3,535 $ 2,463 Severance and production taxes - 24 - 24 Franchise taxes 29 33 89 106 Payroll and other taxes 199 490 745 867 ----------- ----------- ----------- ------------ $ 1,243 $ 1,364 $ 4,369 $ 3,460 =========== =========== =========== ============
Venezuelan municipal taxes for the nine months ended September 30, 2001 include an adjustment of $0.8 million due to a change in tax rates at the South Monagas Unit in Venezuela. In August 2001, Benton-Vinccler entered into settlement agreements with two adjacent municipalities regarding the proper allocation of oil production between the two municipalities and the resulting municipal taxes due for the years 1996 through 2000. The settlement agreements allow Benton-Vinccler to recover over-payment of municipal taxes from one municipality and requires additional municipal tax payments over a two-year period to the second municipality. As of September 2001, the amount of the municipal tax liability was $2.6 million, $1.5 million reflected as accrued expenses and $1.1 million reflected as other liabilities, and the amount of the municipal tax receivable was $2.0 million. TAXES ON INCOME At December 31, 2000, we had, for federal income tax purposes, operating loss carryforwards of approximately $103 million expiring in the years 2003 through 2020. If the carryforwards are ultimately realized, approximately $13 million will be credited to additional paid-in capital for tax benefits associated with deductions for income tax purposes related to stock options. During the nine months ended September 30, 2001, we recorded deferred tax assets generated from current period operating losses and a valuation allowance of $4.7 million. 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. 15 NOTE 6 - OPERATING SEGMENTS We regularly allocate resources to and assess the performance of our 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 USA operating segments are derived primarily from the production and sale of oil and natural gas. Operations included under the heading "USA 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 USA and Other segment and are not allocated to other operating segments.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------------- --------------------------------------- (in thousands) 2001 2000 2001 2000 -------------- ----------------- ---------------- ---------------- OPERATING SEGMENT REVENUES Oil and natural gas sales: Venezuela $31,370 $37,796 $98,552 $101,189 United States and other -- 176 -- 327 -------------- ----------------- ---------------- ---------------- Total oil and gas sales 31,370 37,972 98,552 101,516 -------------- ----------------- ---------------- ---------------- OPERATING SEGMENT INCOME (LOSS) Venezuela 6,056 7,964 16,949 20,011 Russia 2,557 1,821 5,462 2,695 United States and other (6,881) (817) (19,556) (11,005) -------------- ----------------- ---------------- ---------------- Net income (loss) $1,732 $8,968 $2,855 $11,701 ============== ================= ================ ================ SEPTEMBER 30, DECEMBER 31, 2001 2000 ----------------- ----------------- OPERATING SEGMENT ASSETS Venezuela $181,529 $166,462 Russia 100,028 78,406 United States and other 127,832 156,780 -------------- ----------------- Subtotal 409,389 401,648 Intersegment eliminations (100,248) (115,201) -------------- ----------------- Total assets $309,141 $286,447 ============== =================
16 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, Prisklonovoye 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 nine months ended June 30, 2001 and 2000 were 3,751,788 barrels and 3,136,810 barrels, respectively. Prices for crude oil for the nine months ended June 30, 2001 and 2000 averaged $19.06 and $15.70 per barrel, respectively. Depletion expense attributable to Geoilbent for the nine months ended June 30, 2001 and 2000 was $2.65 and $2.20 per barrel, respectively. Unaudited financial information for Geoilbent follows (in thousands). All amounts represent 100 percent of Geoilbent. STATEMENTS OF INCOME:
THREE MONTHS ENDED NINE MONTHS ENDED JUNE 30, JUNE 30, ---------------------------------- ------------------------------- 2001 2000 2001 2000 ------------- ------------- -------------- ------------- Revenues $24,191 $20,748 $71,495 $49,270 ------------- ------------- -------------- ------------- Oil sales 24,191 20,748 71,495 49,270 ------------- ------------- -------------- ------------- Expenses Operating expenses 2,770 2,669 7,572 6,941 Depletion, depreciation and amortization 3,538 2,418 9,942 6,896 General and administrative 1,406 1,216 3,581 2,357 Taxes other than on income 5,703 4,032 20,496 8,733 ------------- ------------- -------------- ------------- 13,417 10,335 41,591 24,927 ------------- ------------- -------------- ------------- Income from operations 10,774 10,413 29,904 24,343 Other Non-Operating Income (Expense) Other income (expense) 178 129 652 (245) Interest expense (1,602) (1,610) (5,574) (5,187) Net gain (loss) on exchange rates 44 (137) 482 (517) ------------- ------------- -------------- ------------- (1,380) (1,618) (4,440) (5,949) ------------- ------------- -------------- ------------- Income before income taxes 9,394 8,795 25,464 18,394 Income tax expense 2,053 1,927 5,393 4,318 ------------- ------------- -------------- ------------- Net income $ 7,341 $ 6,868 $20,071 $14,076 ============= ============= ============== =============
17
BALANCE SHEETS: JUNE 30, SEPTEMBER 30, 2001 2000 ------------ ------------ Current assets: Cash and cash equivalents $ 1,763 $ 2,133 Restricted cash 11,364 12,361 Accounts receivable Trade and other 3,100 2,937 Accrued oil revenue 1,408 3,881 Inventory - materials 15,774 7,955 Prepaid expenses and other 3,865 803 ------------ ------------ Total current assets 37,274 30,070 Other assets 1,148 1,407 Property and equipment Oil and gas properties (full cost method) 239,449 212,308 Accumulated depletion and depreciation (60,439) (50,496) ------------ ------------ 179,010 161,812 ------------ ------------ Total assets $217,432 $193,289 ============ ============ Current liabilities: Accounts payable, trade and other $ 17,152 $ 14,562 Accrued expenses 4,547 4,327 Accrued interest payable 2,636 1,503 Income taxes payable 2,056 1,853 Short-term borrowings 5,192 3,866 Current portion of long-term debt 15,955 10,455 ------------ ------------ Total current liabilities 47,538 36,566 Long-term debt 31,100 38,000 Commitments and contingencies - - Equity Contributed capital 82,518 82,518 Retained earnings 56,276 36,205 ------------ ------------ 138,794 118,723 ------------ ------------ Total liabilities and stockholders' equity $217,432 $193,289 ============ ============
The European Bank for Reconstruction and Development ("EBRD") and International Moscow Bank ("IMB") together have agreed to lend up to $65 million to Geoilbent, based on Geoilbent achieving certain reserve and production milestones, under parallel reserve-based loan agreements. Under these loan agreements, the Company and other shareholders 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. The loans bear an average annual interest rate of 15 percent payable on January 27 and July 27 each year. Principal payments are due in varying installments on the semiannual interest payment dates which began on January 27, 2001 and end on July 27, 2004. 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. Geoilbent began borrowing under these facilities in October 1997 and had borrowed a total of $48.5 million through December 31, 2000. The four-year loan amortization period began in January 2001, and through September 30, 2001 Geoilbent has repaid $10.5 million. The proceeds from the loans were used by Geoilbent to develop the North Gubkinskoye and Prisklonovoye Fields in West Siberia, Russia. 18 During 1996 and 1997, we incurred $4.1 million in financing costs related to the establishment of the EBRD financing, which are recorded in other assets and are subject to amortization over the life of the facility. In 1998, under an agreement with EBRD, Geoilbent ratified an agreement to reimburse us for $2.6 million of such costs, which were then included in accounts receivable. During 2000, Geoilbent paid the accounts receivable. In October 1995, Geoilbent entered into an agreement with Morgan Guaranty for a credit facility under which we provide cash collateral for the loans to Geoilbent. In conjunction with Geoilbent's reserve-based loan agreements with the EBRD and IMB, repayment of the credit facility was subordinated to payments due to the EBRD and IMB and, accordingly, the credit facility was reclassified from current to long-term in 1998. In May 2001, Geoilbent entered into an agreement with IMB to borrow $3.3 million to repay the Morgan credit facility and, as a result, our cash collateral was returned. The loan from IMB is due on November 15, 2002, bears interest at LIBOR plus 6 percent and requires quarterly payments of principal and interest of approximately $0.6 million beginning in August 2001. Excise, pipeline and other tariffs and taxes continue to be levied on all oil producers and certain exporters, including an oil export tariff that decreased to 22 Euros per ton (approximately $2.70 per barrel) on March 18, 2001 from 48 Euros per ton in January 2001. The export tariff increased to 30.5 Euros per ton (approximately $3.64 per barrel) in July 2001. We are unable to predict the impact of taxes, duties and other burdens for the future for our Russian operations. 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 with Arctic Gas, we will earn a 40 percent equity interest in exchange for providing the initial capital needed to achieve economic self-sufficiency through its own oil and gas production. Our capital commitment will be in the form of a credit facility of up to $100 million for the project, the terms and timing of which have yet to be finalized. Pursuant to the Cooperation Agreement, we have 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. As of September 30, 2001, we had loaned $28.5 million to Arctic Gas pursuant to an interim credit facility, with interest at LIBOR plus 3 percent, and had earned the right to remove restrictions from shares representing an approximate 11 percent equity interest. From December 1998 through September 2001, we purchased shares representing an additional 28 percent equity interest not subject to any sale or transfer restrictions. We owned a total of 68 percent of the outstanding voting shares of Arctic Gas as of September 30, 2001, of which approximately 39 percent were not subject to any restrictions. We account for our interest in Arctic Gas using the equity method due to the significant influence we exercise over the operating and financial policies of Arctic Gas. Our share in the losses of Arctic Gas were $0.5 million and $0.7 million for the nine month periods ended June 30, 2001 and 2000, respectively. For the nine months ended June 30, 2001 and 2000, we had a weighted-average equity interest of 29 percent and 26 percent, respectively, not subject to any sale or transfer restrictions. Certain provisions of Russian corporate law would effectively require minority shareholder consent to enter into new agreements between us and Arctic Gas, or change any terms in any existing agreements between the two partners such as the Cooperation Agreement and the Share Disposition Agreement, including the conditions upon which the restrictions on the shares could be removed. 19 Arctic Gas began selling oil in June 2000. Sales quantities attributable to Arctic Gas for the nine months ended June 30, 2001 were 417,612 barrels, prices for crude oil for the nine months ended June 30, 2001 averaged $16.73 per barrel and depletion expense attributable to Arctic Gas for the nine months ended June 30, 2001 was $1.37 per barrel. Summarized unaudited financial information for Arctic Gas follows (in thousands). All amounts represent 100 percent of Arctic Gas. STATEMENTS OF OPERATIONS:
THREE MONTHS ENDED JUNE 30, NINE MONTHS ENDED JUNE 30, ------------------------------------ -------------------------------- 2001 2000 2001 2000 ------------- -------------- ------------- ------------ Oil Sales $ 3,547 $ 1,773 $ 6,988 $ 1,773 Expenses Operating expenses (380) 867 1,855 1,157 Depletion, depreciation and amortization 420 45 733 237 General and administrative 790 600 2,086 1,452 Taxes other than on income 1,026 391 2,799 562 ------------- -------------- ------------ ------------ 1,856 1,903 7,473 3,408 ------------- -------------- ------------ ------------ Income (loss) from operations 1,691 (130) (485) (1,635) Other Non-Operating Income (Expense) Net gain (loss) on exchange rates (23) 2 (305) (235) Interest expense (461) (346) (1,226) (836) ------------ ------------- -------------- ------------ (484) (344) (1,531) (1,071) ------------- -------------- ------------ ------------ Income (loss) before income taxes 1,207 (474) (2,016) (2,706) Income tax expense (benefit) - - (189) - ------------- -------------- ------------ ------------ Net income (loss) $ 1,207 $ (474) $ (1,827) $ (2,706) ============= ============== ============ ============ BALANCE SHEET DATA: JUNE 30, SEPTEMBER 30, 2001 2000 ------------- ------------------- Current assets $ 4,945 $ 1,205 Other assets 13,859 10,120 Current liabilities 33,038 23,955 Net deficit (14,234) (12,630)
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. which have subsequently all been combined into PDVSA Petroleo y Gas, S.A. (all such parent, subsidiary and affiliated entities hereinafter referred to as "PDVSA"). The operating service agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit (the "Unit"). Under the terms of the operating service agreement, Benton-Vinccler, C.A. ("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, including all necessary investments to reactivate and develop the fields comprising the 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 (which amount is periodically adjusted to reflect changes in the average of certain world crude oil prices). The Venezuelan government maintains full ownership of all hydrocarbons in the fields. Currently, we are in discussions with PDVSA regarding the appropriate amount to 20 pay for natural gas produced from the South Monagas Unit and used as fuel in Benton-Vinccler's operations as well as other operating issues. In December 1999, we entered into agreements with Schlumberger and Helmerich & Payne to further develop the South Monagas Unit pursuant to a long-term incentive-based development program. Schlumberger has agreed to financial incentives intended to reduce drilling costs, improve initial production rates of new wells and to increase the average life of the downhole pumps at South Monagas. As part of Schlumberger's commitment to the program, it provides additional technical and engineering resources on-site full-time in Venezuela and at our offices in Carpinteria, California. As of December 31, 2000, 26 new oil wells and 2 re-entry oil wells had been drilled under the alliance program. In January 2001, we suspended the development drilling program until the second half of 2001 in order to thoroughly review all aspects of operations in order to integrate field performance to date with revised computer simulation modeling and improved well completion technology. In August 2001, drilling re-commenced in the Uracoa Field under the alliance agreement with Schlumberger. We anticipate drilling a total of eight new wells in Uracoa and then drill six to ten wells in the Tucupita Field commencing in late 2001 or early 2002. In August 2001, Benton-Vinccler signed an agreement to amend the alliance with Schlumberger. The amended long-term incentive-based alliance continues to provide incentives intended to improve initial production rates of new wells and to increase the average life of the downhole pumps at South Monagas. In addition, Schlumberger has agreed to provide drilling and completion services for new wells utilizing fixed lump-sum pricing. We chose not to renew the alliance with Helmerich & Payne and have entered into a standard drilling contract with Flint. In September 2001, we completed the reservoir simulation study of the Uracoa Field and expect to complete a revised field development plan, incorporating the results of this study, in the early part of 2002. In January 1996, we and our bidding partners, predecessor companies acquired over time by Burlington Resources, Inc. ("Burlington") and Anadarko Petroleum Corporation ("Anadarko"), were awarded the right to explore and develop the Delta Centro Block in Venezuela. The contract required a minimum exploration work program consisting of a seismic survey and the drilling of three wells within five years. At the time the block was tendered for international bidding, PDVSA estimated that this minimum exploration work program would cost $60 million and required that we and the other partners each post a performance surety bond or standby letter of credit for our pro rata share of the estimated work commitment expenditures. We had a 30 percent interest in the exploration venture, with Burlington and Anadarko each owning a 35 percent interest. In July 1996, formal agreements were finalized and executed, and we posted an $18 million standby letter of credit, collateralized in full by a time deposit, to secure our 30 percent share of the minimum exploration work program (see Note 4). During 1999, the Block's first exploration well, the Jarina 1-X, penetrated a thick potential reservoir sequence, but encountered no hydrocarbons. In January 2001, we and our bidding partners reached an agreement with Corporacion Venezolana del Petroleo, S.A. to terminate the contract in exchange for the unused portion of the standby letter of credit of $7.7 million. As a result, we included $7.7 million of restricted cash that collateralized the letter of credit in the Venezuelan full cost pool. As of September 30, 2001, our share of expenditures to date on the Delta Centro Block was $23.1 million. NOTE 9 - UNITED STATES OPERATIONS In April and May 2000, we entered into agreements with Coastline Energy Corporation ("Coastline") for the purpose of acquiring, exploring and developing oil and gas prospects both onshore and in the state waters of the Gulf Coast states of Texas, Louisiana and Mississippi. Under the agreements, Coastline will evaluate prospects in the Gulf Coast area for possible acquisition and development by us. During the 18-month term of the exploration agreement, we will reimburse Coastline for certain of its overhead and prospect evaluation costs. Under the agreements, for prospects evaluated by Coastline that we acquire, Coastline will receive compensation based (a) on oil and natural gas production acquired or developed and (b) on the profits, if any, resulting from the sale of such prospects. In April 2000, pursuant to the agreements, we acquired an approximate 25 percent working interest in the East Lawson Field in Acadia Parish, Louisiana. The acquisition included a 15 percent working interest in two producing oil and natural gas wells. During the year ended December 31, 2000, our share of the East Lawson Field production was 6,884 barrels of oil and 43,352 Mcf of natural gas, resulting in income from United States oil and gas operations of $0.3 million. In December 2000, we sold our interest in the East Lawson Field for $0.8 million in cash. Additionally, we acquired a 100 percent working interest in the Lakeside Exploration Prospect in Cameron Parish, Louisiana. We farmed out 90 percent of the working interest in the prospect for $0.5 million cash and a 16.2 percent carried interest in the first well. We anticipate that drilling of the well will commence before December 2001. The agreement with Coastline was terminated on August 31, 2001. However, certain ongoing operations related to the Lakeside Exploration Prospect may be conducted by Coastline on a consulting basis. 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. In consideration of the 40 percent participation interest in the California Leases, we became the operator of the project and agreed to pay 100 percent of the 21 first $3.7 million and 53 percent of the remainder of the costs of the first well drilled on the block. During 1998, the 2199 #7 exploratory well was drilled to the Gaviota anticline. Drill stem tests proved to be inconclusive or non-commercial, and the well was temporarily abandoned for further evaluation. In November 1998, we entered into an agreement to acquire Molino Energy's interest in the California Leases in exchange for the release of its joint interest billing obligations. In the fourth quarter of 1999, we decided to focus our capital expenditures on existing producing properties and fulfilling work commitments associated with our other properties. 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. However, we continue to evaluate the prospect for potential future drilling activities. NOTE 10 - CHINA OPERATIONS In December 1996, we acquired Benton Offshore China Company, a privately held corporation headquartered in Denver, Colorado, for 628,142 shares of common stock and options to purchase 107,571 shares of our common stock at $7.00 per share, valued in total at $14.6 million. Benton Offshore China Company's primary asset is a large undeveloped acreage position in the South China Sea under a petroleum contract with China National Offshore Oil Corporation ("CNOOC") of the People's Republic of China for an area known as Wan'An Bei, WAB-21. Benton Offshore China Company has, as our wholly owned subsidiary, continued as the operator and contractor of WAB-21. Benton Offshore China Company has submitted an exploration program and budget to CNOOC. However, due to certain territorial disputes over the sovereignty of the contract area, it is unclear when such program will commence. NOTE 11 - RELATED PARTY TRANSACTIONS From 1996 through 1998, we made unsecured loans to our then Chief Executive Officer, A. E. Benton. Each of these loans was evidenced by a promissory note bearing interest at the rate of 6 percent per annum. We subsequently obtained a security interest in Mr. Benton's shares of stock, personal real estate and proceeds from certain contractual and stock option agreements. At December 31, 1998, the $5.5 million owed to us by Mr. Benton exceeded the value of our collateral, due to the decline in the price of our stock. As a result, we recorded an allowance for doubtful accounts of $2.9 million. The portion of the note secured by our stock and stock options, $2.1 million, was presented on the Balance Sheet as a reduction from Stockholders' Equity at December 31, 1998. 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. We recorded an additional $2.8 million allowance for doubtful accounts for the remaining principal and accrued interest owed to us at June 30, 1999, and continue to record additional allowances as interest accrues ($0.9 million for the period July 1, 1999 to September 30, 2001). Measuring the amount of the allowances requires judgments and estimates, and the amount eventually realized may differ from the estimate. In February 2000, we entered into a Separation Agreement and a Consulting Agreement with Mr. Benton, pursuant to which we retained Mr. Benton as an independent contractor to perform certain services for us. Mr. Benton has agreed to propose a plan of reorganization in his bankruptcy case that provides for the repayment of our loans to him. Under the proposed plan, which we anticipate will be submitted to the bankruptcy court in the fourth quarter of 2001 and considered by the bankruptcy court in 2002, we will retain our security interest in Mr. Benton's 600,000 shares of our stock and in his stock options. Repayment of our loans to Mr. Benton may be achieved through Mr. Benton's liquidation of certain real and personal property assets and a phased liquidation of stock resulting from Mr. Benton's exercise of his stock options. The amount that we eventually realize including Benton Oil and Gas Company stock and the timing of receipt of payments will depend upon the timing and results of the liquidation of Mr. Benton's assets. For the nine months ended September 30, 2001 and 2000, we paid to Mr. Benton $116,833 and $298,000, respectively, for services performed under the Consulting Agreement. On May 11, 2001, the Consulting Agreement was terminated. In May 2001, we entered into a Termination Agreement and a Consulting Agreement with our Chairman of the Board, Michael B. Wray. Under the Termination Agreement, Mr. Wray agreed to terminate any employment relationship or officer position with us and any of our subsidiaries and affiliates as of May 7, 2001. As consideration for entering into the Termination Agreement and settlement of all sums owed to Mr. Wray for his services as director through the 2001 Annual Meeting of Stockholders or as an employee, we paid Mr. Wray $100,000. Upon execution of the Termination Agreement, all stock options previously granted to Mr. Wray vested in their entirety. Additionally, under the terms of the Consulting Agreement, Mr. Wray received $100,000 and will provide consulting services on matters pertaining to our business and that of our affiliates through December 31, 2001. 22 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 and Russia, 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, in some cases have affected 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. MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS As a result of our substantial leverage and disappointing financial results prior to 2000, our equity and public debt values have eroded significantly. In order to effectuate the changes necessary to restore our financial flexibility and to enhance our ability to execute a viable strategic plan, we began undertaking several significant actions in 2000, including: - hiring a new President and Chief Executive Officer, a new Senior Vice President and Chief Financial Officer and a new Vice President and General Counsel; - reconstituting our Board of Directors with industry executives with proven experience in oil and natural gas operations, finance and international operations; - redefining our strategic priorities to focus on value creation; - initiating capital conservation steps and financial transactions, including the repurchase of some of our senior notes, designed to de-leverage the Company and improve our cash flow for reinvestment; - undertaking a comprehensive study of our core Venezuelan asset to attempt to enhance the value of its production to ultimately increase cash flow and potentially extend its productive life; - pursuing means to accelerate the commercial development of our Russian assets; - seeking relief from certain restrictive provisions of our debt instruments; and - implementing a plan designed to reduce general and administrative costs at our corporate headquarters by $3 to 4 million, or approximately 50 percent, and to transfer geological and geophysical activities to its overseas offices. We continue to aggressively explore means by which to maximize stockholder value. We believe that we possess significant producing properties in Venezuela which have yet to be optimized and valuable unexploited acreage in Venezuela and Russia. In fact, we believe the seven new wells drilled in the South Tarasovskoye Field since July 2001 significantly increase the value of our Russian properties and we are reviewing alternatives to maximize their value. These alternatives include accelerating the Russian development program and the potential sale of all or part of the Russian assets. However, the intrinsic value of our assets is burdened by a heavy debt load and constraints on capital to further exploit such opportunities. Therefore, we, with the advice of our financial and legal advisers, after having conducted a comprehensive review to consider our strategic alternatives, initiated a process in May 2001 intended to effectively extend the maturity of the senior notes due May 1, 2003 by exchanging new 13.125 percent senior notes due December 2007 plus warrants to purchase shares of our common stock for each of the 2003 Notes. The exchange offer was withdrawn in July 2001 and in August 2001, we solicited and received the requisite consents from the holders of both the 2003 Notes and the 2007 Notes to amend certain covenants in the indentures governing the notes to enable Arctic Gas Company to incur nonrecourse debt of up to $77 million to fund its oil and gas development program. As an incentive to consent, we offered to pay each noteholder an amount in cash equal to $2.50 per $1,000 principal amount of notes held for which executed consents were received. The total amount of consent fees paid to the consenting noteholders was $0.3 million, which has been included in general and administrative expenses. 23 Additionally, we have implemented a plan designed to reduce general and administrative costs at our corporate headquarters by $3-4 million, or approximately 50 percent, and to transfer geological and geophysical activities to our overseas offices in Maturin, Venezuela and in Western Siberia and Moscow, Russia. The reduction in general and administrative costs is being accomplished by reducing our headquarters staff and relocating our headquarters to Houston, Texas from Carpinteria, California. In June 2001, we recorded restructuring charges of $2.1 million, $0.9 million of which are included in general and administrative expenses and $1.2 million of which are included in depletion, depreciation and amortization. The restructuring charges included $0.9 million for severance and termination benefits for 27 employees, $0.8 million for the anticipated loss on subleasing the Carpinteria headquarters and $0.4 million for the reduction in the carrying value of fixed assets that were not transferred to Houston. The implementation of the plan was substantially complete by the end of the third quarter of 2001. We continue to evaluate other strategic alternatives including, but not limited to selling all or part of our existing assets in Venezuela and Russia, or the sale of the Company. However, no assurance can be given that any of these steps can be successfully completed or that we ultimately will determine that any of these steps should be taken. 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 nine months ended September 30, 2001 and 2000 reflect results from Geoilbent and Arctic Gas for the nine months ended June 30, 2001 and 2000, 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: - all capitalized costs (less accumulated amortization and impairment); - the estimated future expenditures (based on current costs) to be incurred in developing proved reserves; and - 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 nine months ended September 30, 2001 and 2000 and the financial condition as of September 30, 2001 and December 31, 2000 in conjunction with our Consolidated Financial Statements and related Notes thereto included in PART I, Item 1, "Financial Statements." The results of operations for the three and nine months ended September 30, 2001 and 2000 are not necessarily indicative of the operating results for a full year or for future operations. THREE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000 Our results of operations for the three months ended September 30, 2001 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted for all of our production and oil sales revenue. As a result of decreased world crude oil prices, oil sales in Venezuela were 17 percent lower in 2001 compared with 2000. Realized fees per barrel decreased 17 percent (from $15.81 in 2000 to $13.15 in 2001) and oil sales quantities were substantially unchanged (2.4 million barrels of oil in 2000 and 2001). Our operating expenses from the South Monagas unit decreased 22 percent primarily due to decreased workover costs. We had revenues of $31.4 million for the three months ended September 30, 2001. The expenses we incurred during the period consisted of: - operating expenses of $9.7 million; - depletion, depreciation and amortization expense of $6.0 million; - general and administrative expense of $5.5 million; - taxes other than on income of $1.2 million; - interest expense of $6.1 million; 24 - income tax expense of $3.5 million; and - minority interest of $1.5 million. Other items of income consisted of: - investment income and other of $0.7 million; - net gain on exchange rates of $0.3 million; and - equity in net earnings of affiliated companies of $2.9 million. Our net income was $1.7 million or $0.05 per share (diluted). By comparison, we had revenues of $38.0 million for the three months ended September 30, 2000. The expenses we incurred during the period consisted of: - operating expenses of $13.0 million; - depletion, depreciation and amortization expense of $4.1 million; - general and administrative expense of $3.8 million; - taxes other than on income of $1.4 million; - interest expense of $7.3 million; - income tax expense of $5.0 million; and - minority interest of $2.0 million. Other items of income consisted of: - investment income and other of $2.2 million; - net gain on exchange rates of $0.1 million; - equity in net earnings of affiliated companies of $2.2 million; and - extraordinary gain on the repurchase of long-term notes of $3.1 million. Our net income was $9.0 million or $0.29 per share (diluted). Our revenues decreased $6.6 million, or 17 percent, during the three months ended September 30, 2001 compared with 2000. This was due to decreased oil sales revenue in Venezuela as a result of decreased world crude oil prices. Our sales quantities for the three months ended September 30, 2001 from Venezuela were 2.4 million barrels (25,900 barrels of oil per day) compared with 2.4 million barrels (26,000 barrels of oil per day) for the three months ended September 30, 2000. Prices for crude oil averaged $13.15 per barrel (pursuant to terms of an operating service agreement) from Venezuela during the three months ended September 30, 2001 compared with $15.81 per barrel during the three months ended September 30, 2000. Our operating expenses decreased $3.3 million, or 25 percent, during the three months ended September 30, 2001 compared with the three months ended September 30, 2000, primarily due to decreased workover costs, partially offset by increased transportation costs. Operating expenses at the South Monagas Unit during the three months ended September 30, 2001 compared with the same period of 2000 were $4.00 per barrel and $5.38 per barrel, respectively. We anticipate that operating expenses at the South Monagas Unit will average between $4.00 and $4.25 per barrel in 2001 and between $3.00 and $3.50 per barrel in 2002. Depletion, depreciation and amortization increased $1.9 million, or 46 percent, during the three months ended September 30, 2001 compared with 2000 primarily due to decreased proved reserves and increased future development costs at the South Monagas Unit, the termination of our exploration obligation on the Delta Centro Block in exchange for our standby letter of credit of $7.7 million in January 2001, and the estimated costs to terminate the building lease of the former Carpinteria, California headquarters office of $0.5 million. Depletion expense per barrel of oil produced from Venezuela during the three months ended September 30, 2001 was $2.12 compared with $1.49 during 2000. General and administrative expenses increased $1.7 million, or 45 percent, during the three months ended September 30, 2001 compared with 2000. This was primarily due to consent fee payments and legal fees totaling $1.2 million associated with the amendment of indenture covenants of our senior unsecured notes and the estimated costs to terminate the building lease of the former Carpinteria, California headquarters office of $0.8 million. Taxes other than on income decreased $0.2 million, or 14 percent, during the three months ended September 30, 2001 compared with the three months ended September 30, 2000 primarily due to reduced oil sales resulting from lower world crude oil prices. 25 Investment income and other decreased $1.5 million, or 68 percent, during the three months ended September 30, 2001 compared with 2000, primarily due to lower average restricted cash and marketable securities balances. Interest expense decreased $1.2 million, or 16 percent, during the three months ended September 30, 2001 compared with 2000. This was primarily due to the reduction of average debt balances, partially offset by a reduction of capitalized interest expense. Net gain on exchange rates increased $0.2 million for the three months ended September 30, 2001 compared with 2000 due to changes in the value of the Bolivar. We realized income before income taxes and minority interest of $3.9 million during the three months ended September 30, 2001 compared with income of $10.7 million in 2000, resulting in decreased income tax expense of $1.5 million. The effective tax rate of 90 percent varies from the U.S. statutory rate of 35 percent primarily because income taxes are paid on profitable operations in foreign jurisdictions and no benefit is provided for net operating losses generated in the U.S. The income attributable to the minority interest decreased $0.5 million for the three months ended September 30, 2001 compared with 2000, primarily due to the decreased profitability of Benton-Vinccler. Equity in net earnings of affiliated companies increased $0.7 million, or 32 percent, during the three months ended September 30, 2001 compared with 2000. This was due to increased income from Geoilbent and Arctic Gas. Our share of earnings from Geoilbent was $2.5 million for the three months ended June 30, 2001 compared with earnings of $2.3 million for 2000. The increase of $0.2 million, or 8 percent, was primarily due to increased sales quantities and world crude oil prices partially offset by increased depletion and taxes other than on income. Prices for Geoilbent's crude oil averaged $19.01 per barrel during the three months ended June 30, 2001 compared with $17.19 per barrel for the three months ended June 30, 2000. Our share of Geoilbent oil sales quantities increased by 22,335 barrels, or 5 percent, from 410,376 barrels sold during the three months ended June 30, 2000 to 432,711 barrels sold during the three months ended June 30, 2001. Our share of earnings from Arctic Gas was $0.3 million for the three months ended June 30, 2001 compared with a loss of $0.1 million for 2000. The increase of $0.4 million was primarily due to increased oil sales quantities. NINE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000 We had revenues of $98.6 million for the nine months ended September 30, 2001. The expenses we incurred during the period consisted of: - operating expenses of $32.2 million; - depletion, depreciation and amortization expense of $18.7 million; - write-downs of oil and gas properties and impairments of $0.4 million; - general and administrative expense of $15.9 million; - taxes other than on income of $4.4 million; - interest expense of $18.5 million; - income tax expense of $10.6 million; and - minority interest of $4.4 million. Other items of income consisted of: - investment income and other of $2.4 million; - net gain on exchange rates of $0.5 million; and - equity in net earnings of affiliated companies of $6.3 million. Our net income was $2.9 million or $0.08 per share (diluted). By comparison, we had revenues of $101.5 million for the nine months ended September 30, 2000. The expenses we incurred during the period consisted of: - operating expenses of $34.8 million; - depletion, depreciation and amortization expense of $11.7 million; - write-downs of oil and gas properties and impairments of $1.1 million; - general and administrative expense of $12.3 million; - taxes other than on income of $3.5 million; - interest expense of $22.2 million; - income tax expense of $13.3 million; and - minority interest of $5.0 million. 26 Other items of income consisted of: - investment income and other of $6.6 million; - net gain on exchange rates of $0.2 million; - equity in net earnings of affiliated companies of $4.1 million; and - extraordinary gain on the repurchase of long-term notes of $3.1 million. Our net income was $11.7 million or $0.39 per share (diluted). Our revenues decreased $2.9 million, or 3 percent, during the nine months ended September 30, 2001 compared with 2000. This was due to decreased oil sales revenue in Venezuela as a result of decreases in world crude oil prices substantially offset by increased sales quantities. Our sales quantities for the nine months ended September 30, 2001 from Venezuela were 7.4 million barrels (27,000 barrels of oil per day) compared with 6.9 million barrels (25,100 barrels of oil per day) for the nine months ended September 30, 2000. The increase in sales quantities of 481,055 barrels, or 7 percent, was primarily due to the infill drilling program that began in January 2000 and ended in December 2000. Prices for crude oil averaged $13.39 per barrel (pursuant to terms of an operating service agreement) from Venezuela during the nine months ended September 30, 2001 compared with $14.71 per barrel during the nine months ended September 30, 2000. Our operating expenses decreased $2.6 million, or 7 percent, during the nine months ended September 30, 2001 compared with the nine months ended September 30, 2000. This was primarily due to decreased workover costs substantially offset by a 7 percent increase in oil production at the South Monagas Unit in Venezuela, increased electricity and transportation costs. Operating expenses at the South Monagas Unit during the nine months ended September 30, 2001 compared with the same period of 2000 were $4.30 per barrel and $4.98 per barrel, respectively. Depletion, depreciation and amortization increased $7.0 million, or 60 percent, during the nine months ended September 30, 2001 compared with 2000 primarily due to increased oil production, decreased proved reserves and increased future development costs at the South Monagas Unit, the termination of our exploration obligation on the Delta Centro Block in exchange for our standby letter of credit of $7.7 million in January 2001, the estimated costs to terminate the building lease of the former Carpinteria, California headquarters office of $1.4 million, and a reduction in the carrying value of fixed assets that will not be transferred to Houston of $0.4 million. Depletion expense per barrel of oil produced from Venezuela during the nine months ended September 30, 2001 was $2.12 compared with $1.48 during 2000. We recognized write-downs of $0.4 million and $1.1 million at September 30, 2001 and 2000, respectively, of capitalized costs associated with exploration prospects. The write-downs were primarily related to costs associated with the California Leases in 2001 and the Jordan PSA in 2000. General and administrative expenses increased $3.6 million, or 29 percent, during the nine months ended September 30, 2001 compared with 2000. This was primarily due to severance and termination benefits for 27 employees of $0.9 million associated with the reduction in force and corporate restructuring plan adopted in June 2001, legal and professional fees of $1.0 million associated with the offer to restructure our senior notes due May 1, 2003, consent fee payments and legal fees totaling $1.2 million associated with the amendment of indenture covenants of our senior unsecured notes, the estimated costs to terminate the building lease of the former Carpinteria, California headquarters office of $0.8 million, and severance payments aggregating $0.9 million to two executive officers who resigned during the first quarter of 2001. These increases were partially offset by the reduction in our headquarters staff and the relocation of our headquarters to Houston, Texas. Taxes other than on income increased $0.9 million, or 26 percent, during the nine months ended September 30, 2001 compared with the nine months ended September 30, 2000 primarily due to a one-time municipal tax adjustment due to a change in tax rates at the South Monagas Unit in Venezuela, substantially offset by decreased oil sales revenue. Investment income and other decreased $4.2 million, or 64 percent, during the nine months ended September 30, 2001 compared with 2000, primarily due to lower average restricted cash and marketable securities balances. Interest expense decreased $3.7 million, or 17 percent, during the nine months ended September 30, 2001 compared with 2000. This was primarily due to the reduction of average debt balances, partially offset by a reduction of capitalized interest expense. Net gain on exchange rates increased $0.3 million for the nine months ended September 30, 2001 compared with 2000 due to changes in the value of the Bolivar. We realized income before income taxes and minority interests of $11.5 million during the nine months ended September 30, 2001 compared with income of $22.8 million in 2000, resulting in decreased income tax expense of $2.7 million. The effective tax rate of 92 percent varies from the U.S. statutory rate of 35 percent primarily because income taxes are paid on profitable operations in foreign jurisdictions and no benefit is provided for net operating losses generated in the U.S. The income attributable to the minority interest decreased $0.6 million for the nine months ended September 30, 2001 compared with 2000, primarily due to the decreased profitability of Benton-Vinccler. Equity in net earnings of affiliated companies increased $2.2 million, or 54 percent, during the nine months ended September 30, 2001 compared with 2000. This was primarily due to increased income from Geoilbent and decreased losses from Arctic Gas. Our 27 share of earnings from Geoilbent was $6.8 million for the nine months ended June 30, 2001 compared with earnings of $4.8 million for 2000. The increase of $2.0 million, or 42 percent, was due to higher world crude oil prices and increased sales quantities. Prices for Geoilbent's crude oil averaged $19.06 per barrel during the nine months ended June 30, 2001 compared with $15.70 per barrel for the nine months ended June 30, 2000. Our share of Geoilbent oil sales quantities increased by 209,093 barrels, or 20 percent, from 1,066,515 barrels sold during the nine months ended June 30, 2000 to 1,275,608 barrels sold during the nine months ended June 30, 2001. Our share of losses from Arctic Gas was $0.5 million for the nine months ended June 30, 2001 compared with losses of $0.7 million for 2000. The decrease of $0.2 million, or 29 percent, was primarily due to initiation of oil sales in June 2000. 28 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: - drilling and completion costs of wells and the cost of production and transportation facilities; - geological, geophysical and seismic costs; and - 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. 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 to make loan repayments, dividend and other cash payments to us. Debt Reduction and Restructuring Program. We currently have significant debt principal obligations payable in 2003 ($108 million) and 2007 ($105 million). As described below, we have reduced our obligations due in 2003 by $17 million since September 10, 2000. During September 2000, we exchanged 2.7 million shares of our common stock, plus accrued interest, for $8 million face value of the 11.625 percent senior unsecured notes, and we purchased $5 million face value of the 11.625 percent senior unsecured notes for cash of $3.5 million, plus accrued interest. Additionally, in November 2000, we exchanged 1.5 million shares of our common stock, plus accrued interest, for an aggregate of $4 million face value of the 11.625 percent senior unsecured notes. We anticipate continuing to exchange our common stock or cash for such notes at a substantial discount to their face value, if available on economic terms and subject to certain limitations. Under the rules of The New York Stock Exchange, our common stockholders would need to approve the issuance of an aggregate of more than 5.9 million shares of common stock in exchange for senior notes. The effect of further issuances in excess of 5.9 million shares of common stock in exchange for senior notes will be to materially dilute the existing stockholders if material portions of the senior notes are exchanged. The dilutive effect on the common stockholders would depend upon a number of factors, the primary ones being the number of shares issued, the price at which the common stock is issued, and the discount on the senior notes exchanged. In May 2001, we initiated a process intended to effectively extend the maturity of the senior notes due May 1, 2003 by exchanging new 13.125 percent senior notes due December 2007 plus warrants to purchase shares of our common stock for each of the 2003 Notes. The exchange offer was withdrawn in July 2001 and in August 2001, we solicited and received the requisite consents from the holders of both the 2003 Notes and the 2007 Notes to amend certain covenants in the indentures governing the notes to enable Arctic Gas Company to incur nonrecourse debt of up to $77 million to fund its oil and gas development program. As an incentive to consent, we offered to pay each noteholder an amount in cash equal to $2.50 per $1,000 principal amount of notes held for which executed consents were received. The total amount of consent fees paid to the consenting noteholders was $0.3 million. Working Capital. Our capital resources and liquidity are affected by the timing of our semiannual interest payments of approximately $11.2 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 regarding the South Monagas Unit. 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. In October 2000, an uncommitted short-term working capital facility of 8 billion Bolivars (approximately $11 million) was made 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 borrowed 5.4 billion Bolivars (approximately $7.7 million) in January 2001 under this facility, which we repaid in February 2001. Again in October 2001, we borrowed 5 billion Bolivars (approximately $6.7 million) under the facility which will be repaid in November 2001 after the receipt of the third quarter payment from PDVSA. We believe that similar arrangements will be available to us in future quarters. At September 30, 2001, the facility had no outstanding balance. We will need additional funds in the future for both the development of our assets and the service of our debt, including the debt maturing in 2003. Therefore, we will be required to develop sources of additional capital and/or reduce or reschedule our cash requirements by various techniques including, but not limited to, the pursuit of one or more of the following strategic alternatives: 29 - reducing the total debt outstanding by exchanging debt for equity or by repaying debt with proceeds from the sale of assets, each on appropriate terms; - managing the scope and timing of our capital expenditures, substantially all of which are within our discretion; - forming joint ventures or alliances with financial or other industry partners; - selling all or a portion of our existing assets, including interests in our assets; - issuing debt or equity securities or otherwise raise additional funds; - merging or combining with another entity or sell the Company; or - reducing our cost structure. There can be no assurance that any of the above alternatives, or some combination thereof, will be available or, if available, will be on terms acceptable to us. The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below: NINE MONTHS ENDED SEPTEMBER 30, ---------------------------- 2001 2000 ------------- ------------- Net cash provided by operating activities $ 34,663 $ 46,575 Net cash used in investing activities (37,701) (43,790) Net cash provided by (used in) financing activities 6,367 (2,816) ------------- ------------- Net increase (decrease) in cash $ 3,329 $ (31) ============= ============= At September 30, 2001, we had current assets of $60.4 million and current liabilities of $56.8 million, resulting in working capital of $3.6 million and a current ratio of 1.06 to 1. This compares with our working capital of $12.3 million and a current ratio of 1.24 to 1 at December 31, 2000. The decrease in working capital of $8.7 million was primarily due to capital expenditures at the South Monagas Unit, partially offset by long-term debt incurred by Benton-Vinccler for the construction of a 31-mile pipeline, payment of semi-annual interest on senior unsecured notes and additional investments in Arctic Gas Company. Cash Flow from Operating Activities. During the nine months ended September 30, 2001 and 2000, net cash provided by operating activities was approximately $34.7 million and $46.6 million, respectively. Cash flow from operating activities decreased by $11.9 million during the nine months ended September 30, 2001 compared with 2000. This was primarily due to reductions in accounts payable and accrued expenses, increased general and administrative expenses and decreased investment income which were substantially offset by increased collections of accrued revenues, reduced interest payments and reduced operating expenses. Cash Flow from Investing Activities. During the nine months ended September 30, 2001 and 2000, we had drilling and production related capital expenditures of approximately $34.6 million and $40.1 million, respectively. Of the 2001 expenditures: - $26.0 million was attributable to the development of the South Monagas Unit in Venezuela; - $7.7 million was related to costs on the Delta Centro Block in Venezuela; and - $0.9 million was attributable to other projects. In addition, during the nine months ended September 30, 2001, we increased our investment in Arctic Gas by $15.2 million, consisting of purchases of additional shares totaling $4.7 million, additional loans of $6.5 million and other costs, consisting primarily of geological and geophysical costs, of $4.0 million. As a result of the decline in oil prices, in 1999 we instituted a capital expenditure program to reduce expenditures to those that we believed were necessary to maintain current producing properties. In the second half of 1999, oil prices recovered substantially. In December 1999, we entered into incentive-based development alliance agreements with Schlumberger and Helmerich & Payne as part of our plans to resume development of the South Monagas Unit in Venezuela. During 2000, we drilled 26 new oil wells and re-entered 2 oil wells in the Uracoa Field under the alliance agreements utilizing Schlumberger's technical and engineering resources. As part of our strategic shift in focus on the value of the barrels produced, in January 2001 we suspended the development drilling program in Venezuela until the second half of 2001. During this period, with the assistance of alliance partner Schlumberger, all aspects of operations are being thoroughly reviewed to integrate field performance to date with revised computer simulation modeling and improved well completion technology. We expect the result will be a streamlined and more effective infill drilling and well workover program that is part of an overall reservoir management strategy to drain the remaining estimated 123 million barrels (98 million barrels net to Benton) of proved reserves of oil in the fields. Our goal will be an accelerated development 30 program with lower cost production rising to an expected level of up to between 31,000 to 33,000 barrels of oil equivalent per day in less than two years. In August 2001, drilling re-commenced in the Uracoa Field under the alliance agreement with Schlumberger. We anticipate drilling a total of eight new wells in Uracoa and drill six to ten wells in the Tucupita Field commencing in late 2001 or early 2002. In August 2001, Benton-Vinccler signed an agreement to amend the alliance with Schlumberger. The amended long-term incentive-based alliance continues to provide incentives intended to improve initial production rates of new wells and to increase the average life of the downhole pumps at South Monagas. In addition, Schlumberger has agreed to provide drilling and completion services for new wells utilizing fixed lump-sum pricing. We chose not to renew the alliance with Helmerich & Payne and have entered into a standard drilling contract with Flint. In September 2001, we completed the reservoir simulation study of the Uracoa Field and expect to complete a revised field development plan, incorporating the results of this study, in the early part of 2002. Results of the first three wells drilled under the renewed development drilling program have been successful with initial production rates approximately double the initial production rates of the wells drilled in 2000. We expect capital expenditures of approximately $20 to 25 million during the next 12 months, substantially all of which will be at the South Monagas Unit. Additionally, we are negotiating a loan for Arctic Gas that is expected to minimize future investments in Arctic Gas. In addition, we anticipate providing or arranging loans of up to $100 million over time to Arctic Gas pursuant to an equity acquisition agreement signed in April 1999; to date, we have loaned Arctic Gas $28.5 million under this agreement. We continue to evaluate funding alternatives for the loans to Arctic Gas. In August 2001, we solicited and received the requisite consents from the holders of both the 2003 Notes and the 2007 Notes to amend certain covenants in the indentures governing the notes to enable Arctic Gas Company to incur nonrecourse debt of up to $77 million to fund its oil and gas development program. The timing and size of the investments for the South Monagas Unit and Arctic Gas are substantially at our discretion. We anticipate that Geoilbent will continue to fund its expenditures through its own cash flow 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 $22 million related to our outstanding senior notes during the next 12 months. We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements. The results from the new wells drilled in the Uracoa Field in Venezuela indicate that the reservoir formation quality is as expected, but may be sensitive to drilling and completion practices. Additionally, a number of previously producing wells went off production during 2000, requiring maintenance operations. We are working with our alliance partner on techniques to optimize the production from new wells and believe that we can achieve improvements in production performance from the Uracoa Field. Results of the first four wells drilled under the renewed 2001 development drilling program illustrate significant progress in optimizing production from new wells with initial production rates approximately double the initial production rates of the wells drilled in 2000. Current production from Arctic Gas' Samburg license block is approximately 2,700 barrels of oil per day and current production from Geoilbent's North Gubkinskoye and Prisklonovoye Fields is approximately 14,000 barrels of oil per day. Additionally, in July 2001, Geoilbent commenced oil production from the first development well in the South Tarasovskoye Field. The well, drilled to a total depth of 9,535 feet, encountered a 365 foot gross oil column in multiple productive intervals, and established the first production from the Geoilbent 100 percent owned Urabor Yakhinsky Block in Western Siberia, Russia. During the third quarter, Geoilbent drilled four additional wells in the South Tarasovskoye Field, which are currently producing approximately 6,000 barrels per day. The initial discovery and production from this field came from the adjacent Purneftegaz acreage in May of this year. Evaluation of the exploratory appraisal well to test the extension of the South Tarasovskoye Field is continuing. At least one more exploration well and follow up exploitation drilling will be required to determine the full significance of the South Tarasovskoye Field. We believe this field could add significant, high quality reserves and cash flow to our Russian assets. We believe the seven new wells drilled in the South Tarasovskoye Field since July 2001 significantly increase the value of our Russian properties and we are reviewing alternatives to maximize their value. These alternatives include accelerating the Russian development programs and the potential sale of all or part of the Russian assets. Cash Flow from Financing Activities. In May 1996, we issued $125 million in 11.625 percent senior unsecured notes due May 1, 2003, of which we repurchased $17 million at their discounted value in September and November 2000. The notes were repurchased with the issuance of 4.2 million common shares and cash of $3.5 million plus accrued interest. In November 1997, we issued $115 million in 9.375 percent senior unsecured notes due November 1, 2007, of which we subsequently repurchased $10 million at their par value for cash. Interest on all of the notes is due May 1 and November 1 of each year. The indenture agreements provide for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. At September 30, 2001, we were in compliance with all covenants of the indentures. 31 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 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 interest rate for the quarter ending September 2001 was 21 percent with an effective interest rate of 7.8 percent taking into account exchange rate gains resulting from devaluation of the Bolivar during the quarter. We recently received a letter from the New York Stock Exchange ("NYSE") notifying us that we have fallen below the continued listing standards 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 as of June 30, 2001, was $14.3 million ($16 million at September 30, 2001). In accordance with the NYSE's rules, we intend to submit a plan to the NYSE by mid-December detailing how we expect to reestablish compliance with the listing criteria within the next 18 months. The NYSE is expected to respond to the plan within 45 days after it is submitted. Because of our ongoing efforts to implement our strategic plan for improvements and to evaluate alternatives to restore our financial flexibility, we believe that we will be able to meet the NYSE's continued listing standards in the future. These alternatives include continued cost reductions, production enhancements, selling all or part of our assets in Venezuela and/or Russia, restructuring the debt or some combination of these alternatives. We may also recommend selling the Company. However, we cannot give any assurance that any of these steps can be successfully completed or that we ultimately will determine that any of these steps should be taken. Failure to meet the NYSE criteria may result in the delisting of our common stock on the NYSE. As a result, an investor may find it more difficult to dispose or obtain quotations or market value of our common stock, which may adversely affect the marketability of our common stock. However, given our strategic plan referenced above, we are optimistic that we will be able to meet the NYSE requirements in the future and consequently, do not expect our stock to be delisted. CONCLUSION While no assurance can be given, we currently believe that we have sufficient flexibility with our discretionary capital expenditures and investments in and advances to affiliates that our capital resources and liquidity will be adequate to fund our semiannual interest payment obligations for the next 12 months. This expectation is based upon our current estimate of projected price levels, production and the availability of short-term working capital facilities of up to $11 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 are significant additional decreases in crude oil prices or decreases in 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 $0.8 million based on our third quarter production rates and cost structure. However, our ability to retire our long-term debt obligations due in the year 2003 is highly dependent upon our success in pursuing some or all of the strategic alternatives described above. There can be no assurance that such efforts will produce enough cash for retirement of these obligations or that these obligations could be refinanced or restructured. DOMESTIC OPERATIONS In April and May 2000, we entered into agreements with Coastline Energy Corporation ("Coastline") for the purpose of acquiring, exploring and developing oil and natural gas prospects both onshore and in the state waters of the Gulf Coast states of Texas, Louisiana and Mississippi. Under the agreements, Coastline evaluated prospects in the Gulf Coast area for possible acquisition and development by us. During the 18-month term of the exploration agreement, we reimbursed Coastline for certain of its overhead and prospect evaluation costs. Under the agreements, for prospects evaluated by Coastline and that we acquire, Coastline will receive compensation based on (a) oil and natural gas production acquired or developed and (b) the profits, if any, resulting from the sale of such prospects. In April 2000, pursuant to the agreements, we acquired an approximate 25 percent working interest in the East Lawson Field in Acadia Parish, Louisiana. The acquisition included a 15 percent working interest in two producing oil and natural gas wells. During the year ended December 31, 2000, our share of the East Lawson Field production was 6,884 barrels of oil and 43,352 Mcf of natural gas, resulting in income from United States oil and natural gas operations of $0.3 million. In December 2000, we sold our interest in the East Lawson Field for $0.8 million in cash. Additionally, we acquired a 100 percent 32 working interest in the Lakeside Exploration Prospect in Cameron Parish, Louisiana. We farmed out 90 percent of the working interest in the prospect for $0.5 million cash and a 16.2 percent carried interest in the first well. We anticipate that drilling of the well will commence before December 2001. The agreement with Coastline was terminated on August 31, 2001. However, certain ongoing operations related to the Lakeside Exploration Prospect may be conducted by Coastline on a consulting basis. 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. In consideration of the 40 percent participation interest in the California Leases, we became the operator of the project and agreed to pay 100 percent of the first $3.7 million and 53 percent of the remainder of the costs of the first well drilled on the block. During 1998, the 2199 #7 exploratory well was drilled to the Gaviota anticline. Drill stem tests proved to be inconclusive or non-commercial, and the well was temporarily abandoned for further evaluation. In November 1998, we entered into an agreement to acquire Molino Energy's interest in the California Leases in exchange for the release of their joint interest billing obligations. In the fourth quarter of 1999, we decided to focus our capital expenditures on existing producing properties and fulfilling work commitments associated with our other properties. 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. However, we continue to evaluate the prospect for potential future drilling activities. 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 Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit (the "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, including all necessary investments to reactivate and develop the fields comprising the Unit. The Venezuelan government maintains full ownership of all hydrocarbons in the fields. As a private contractor, Benton-Vinccler is subject to a statutory income tax rate of 34 percent. However, Benton-Vinccler reported significantly lower effective tax rates for 1998 due to the effect of the devaluation of the Bolivar while Benton-Vinccler uses the U.S. dollar as its functional currency. We cannot predict the timing or impact of future devaluations in Venezuela. 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. China's claim of ownership of the area results from China's discovery and use and historic administration of the area. This claim also includes third party and official foreign government recognition of China's sovereignty and jurisdiction over the contract area. Despite this claim, the territorial dispute may not be resolved in favor of China. We cannot predict how or when, if at all, this dispute will be resolved or whether it would result in our interest being reduced. Benton Offshore China Company has submitted plans and budgets to CNOOC for an initial seismic program to survey the area. However, exploration activities will be subject to resolution of such territorial dispute. At September 30, 2001, we had recorded no proved reserves attributable to this petroleum contract. 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 will earn a 40 percent equity interest in exchange for providing the initial capital needed to achieve the economic self-sufficiency through its own oil and natural gas production. Our capital commitment will be in the form of a credit facility of up to $100 million for the project, the terms and timing of which are being negotiated but have yet to be finalized. Pursuant to the Cooperation Agreement, we have 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. Due to the 33 significant influence we exercise over the operating and financial policies of Arctic Gas, we account for our interest in Arctic Gas using the equity method. Certain provisions of Russian corporate law would effectively require minority shareholder consent to enter into new agreements between us and Arctic Gas, or to change any terms in any existing agreements, including the conditions upon which the restrictions on the shares could be removed. As of September 30, 2001, we had loaned $28.5 million to Arctic Gas pursuant to an interim credit facility, with interest at LIBOR plus 3 percent, and had earned the right to remove restrictions from shares representing an approximate 11 percent equity interest. From December 1998 through September 2001, we purchased shares representing an additional 28 percent equity interest not subject to any sale or transfer restrictions. We owned a total of 68 percent of the outstanding voting shares of Arctic Gas as of September 30, 2001, of which approximately 39 percent were not subject to any restrictions. In 1991, we entered into a joint venture agreement with Purneftegazgeologia and Purneftegaz forming Geoilbent for the purpose of developing, producing and marketing crude oil from the North Gubkinskoye and Prisklonovoye Fields in the West Siberia region of Russia located approximately 2,000 miles northeast of Moscow. Geoilbent was later re-chartered as a limited liability company. We own 34 percent and Purneftegazgeologia and Purneftegaz each own 33 percent of Geoilbent. The field covers 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. Geoilbent also holds rights to three more license blocks comprising 1,189,757 acres. Geoilbent commenced initial operations in the North Gubkinskoye and Prisklonovoye Fields during the third quarter of 1992 with the construction of a 37-mile oil pipeline and installation of temporary production facilities. In July 2001, Geoilbent commenced production from a development wells in the South Tarasovskoye Field. Russian companies are subject to a statutory income tax rate of up to 35 percent and are subject to various other tax burdens and tariffs. Excise, pipeline and other tariffs and taxes continue to be levied on all oil producers and certain exporters, including an oil export tariff that decreased to 22 Euros per ton (approximately $2.70 per barrel) on March 18, 2001 from 48 Euros per ton in January 2001. The export tariff increased to 30.5 Euros per ton (approximately $3.64 per barrel) in July 2001. We are unable to predict the impact of taxes, duties and other burdens for the future for our Russian operations. 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 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 nine months ended September 30, 2001, net foreign exchange gains attributable to our Venezuelan operations were $0.5 million and net foreign exchange gains attributable to our Russian operations were $0.2 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. 34 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. NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141, "Business Combinations," SFAS 142 "Goodwill and Other Intangible Assets" and SFAS 143 "Accounting for Asset Retirement Obligations." SFAS 141 eliminates the pooling method of accounting for a business combination, except for qualifying business combinations that were initiated prior to July 1, 2001, and requires that all combinations be accounted for using the purchase method. SFAS 142, which is effective for fiscal years beginning after December 15, 2001, addresses accounting for identifiable intangible assets, eliminates the amortization of goodwill and provides specific steps for testing the impairment of goodwill. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives. SFAS 143, which is effective for fiscal years beginning after June 15, 2002, requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred as a capitalized cost of the long-lived asset and to depreciate it over its useful life. We are currently in the process of evaluating the impact that SFAS 142 and SFAS 143 will have on our financial position and results of operations. In October 2001, the FASB issued SFAS 144, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121 and the accounting and reporting provisions of APB Opinion No. 30. SFAS 144 is effective for fiscal years beginning after December 15, 2001. We are currently in the process of evaluating the impact that SFAS 144 will have on our financial position and results of operations. 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 per barrel in 1998 and increased to $14.94 per barrel in 2000. During the nine months ended September 30, 2001, the average realization in Venezuela was $13.39 per barrel. Based on our budgeted production and costs, we will require an average realization in Venezuela of approximately $12.50 per barrel in 2001 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 nine months ended September 30, 2001 or 2000. INTEREST RATES Total long-term debt at September 30, 2001 consisted of $213 million of fixed-rate senior unsecured notes maturing in 2003 ($108 million) and 2007 ($105 million) and $11.1 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 nine months ended September 30, 2001. 35 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 U.S. dollars; 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. 36 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS On February 17, 1998, the WRT Creditors Liquidation Trust ("WRT 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 (the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was insolvent at the time of its acquisition of the properties and that it paid a price in excess of the fair value of the property. A trial commenced on May 1, 2000 that concluded at the end of August 2000, and post trial briefs were filed. In August 2001, a favorable decision was rendered in BOGLA's favor denying any and all relief to the WRT Trust. The WRT Trust has stated that it would appeal the decision prior to the end of 2001; however, we believe that any such appeal would result in an outcome consistent with the court's prior decision. ITEM 2. CHANGES IN SECURITIES None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS At our Annual Meeting of Stockholders held on July 30, 2001, the following items were voted on by the Stockholders in addition to the election of directors: 1. To approve the 2001 Long-Term Stock Incentive Plan: Votes in Favor Votes Against/Withheld Abstentions/Broker Non-Votes -------------------- -------------------------- ------------------------------- 16,265,425 2,371,951 13,593,860 2. To ratify the appointment of PricewaterhouseCoopers LLP as the independent accountants for the year ended December 31, 2001: Votes in Favor Votes Against/Withheld Abstentions/Broker Non-Votes -------------------- -------------------------- ------------------------------- 31,944,893 140,253 146,090 ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 10.1 Amendment to Benton Oil and Gas Company Non-Employee Director Stock Purchase Plan. (b) Reports on Form 8-K On July 19, 2001, we filed a report on Form 8-K, under Item 5, "Other Events" regarding the termination of the previously announced exchange offer and consent solicitation. On August 31, 2001, we filed a report on Form 8-K, under Item 5, "Other Events" regarding the receipt of the requisite consents to amend the indentures governing our senior notes due in 2003 and 2007. 37 SIGNATURES Pursuant to the requirements of Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. BENTON OIL AND GAS COMPANY Dated: November 12, 2001 By: /s/ Peter J. Hill ------------------ Peter J. Hill President and Chief Executive Officer Dated: November 12, 2001 By: /s/ Steven W. Tholen --------------------- Steven W. Tholen Senior Vice President of Finance and Administration and Chief Financial Officer