-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, JhQ4NrXeip1jF4E3tVN1tsQsTLbQIoUHoXx0//EbgBJjKhpxvJDcIf2XbeNERqr+ wdkfvTWddpvQNZGQfGAqDA== 0000950152-01-002063.txt : 20010409 0000950152-01-002063.hdr.sgml : 20010409 ACCESSION NUMBER: 0000950152-01-002063 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010402 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BENTON OIL & GAS CO CENTRAL INDEX KEY: 0000845289 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 770196707 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-10762 FILM NUMBER: 1590496 BUSINESS ADDRESS: STREET 1: 6267 CARPINTERIA AVE. STREET 2: SUITE 200 CITY: CARPINTERIA STATE: CA ZIP: 93013 BUSINESS PHONE: 8055665600 MAIL ADDRESS: STREET 1: 1145 EUGENIA PL STREET 2: STE 200 CITY: CARPINTERIA STATE: CA ZIP: 93013 10-K 1 l86922ae10-k.txt BENTON OIL AND GAS COMPANY 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (MARK ONE) Annual Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934 [X] For the fiscal year ended December 31, 2000 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 (IRS Employer Identification Number) INCORPORATION OR ORGANIZATION) 6267 CARPINTERIA AVENUE, SUITE 200 CARPINTERIA, CALIFORNIA 93013 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) Registrant's telephone number, including area code (805) 566-5600 Securities registered pursuant to Section 12(b) of the Act: TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED - ------------------- ----------------------------------------- Common Stock, $.01 Par Value NYSE Securities registered pursuant to Section 12(g) of the Act: TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED - ------------------- ----------------------------------------- Common Stock Purchase Warrants, NASDAQ $11.00 exercise price 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 [ ] On March 28, 2001, the aggregate market value of the shares of voting stock of Registrant held by non-affiliates was approximately $66,943,032 based on a closing sales price on NYSE of $2.00 As of March 28, 2001, 33,946,919 shares of the Registrant's common stock were outstanding. DOCUMENT INCORPORATED BY REFERENCE Portions of the Registrant's Proxy Statement for the 2001 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of its fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items, 10, 11, 12, and 13 of Part III of this annual report. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.[ ] 2 2 BENTON OIL AND GAS COMPANY FORM 10-K TABLE OF CONTENTS Page ---- Part I - ------ Item 1. Business.....................................................3 Item 2. Properties..................................................21 Item 3. Legal Proceedings...........................................21 Item 4. Submission of Matters to a Vote of Security Holders ........22 Part II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.....................23 Item 6. Selected Consolidated Financial Data........................24 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................26 Item 7A. Quantitative and Qualitative Disclosures about Market Risk.........................................40 Item 8. Financial Statements and Supplemental Data..................40 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .............40 Part III Item 10. Directors and Executive Officers of the Registrant .........41 Item 11. Executive Compensation......................................41 Item 12. Security Ownership of Certain Beneficial Owners and Management...........................41 Item 13. Certain Relationships and Related Transactions .............41 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.............................42 Financial Statements.......................................................44 Signatures.................................................................77 3 3 PART I The Company cautions 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 management of the Company 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, the Company cautions that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include the Company's substantial concentration of operations in Venezuela, the political and economic risks associated with international operations, the anticipated future development costs for the Company's undeveloped proved reserves, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain key employees of the Company, 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. See Risk Factors included in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations. ITEM 1 BUSINESS GENERAL Benton Oil and Gas Company is an independent energy company which has been engaged in the development and production of oil and gas properties since 1989. We have developed significant interests in Venezuela and Russia, and have acquired certain less significant interests in other parts of the world. Our producing operations are conducted principally through our 80 percent-owned Venezuelan subsidiary, Benton-Vinccler, C.A., which operates the South Monagas Unit in Venezuela; and Geoilbent Ltd., a Russian limited liability company of which we own 34 percent, which operates the North Gubkinskoye Field in West Siberia, Russia. Additionally, we own 60 percent of the equity interest in Arctic Gas Company, of which 31 percent was subject to restrictions on transfer and 29 percent was not subject to restrictions on transfer, as of December 31, 2000. Arctic Gas was formed to explore and develop the Samburg and Yevo-Yakha License Blocks in the West Siberian Basin of Russia. We have expanded into projects which involve exploration components, such as opportunities in China, through our acquisition of the WAB-21 Exploration Block and the Molino oil and natural gas project in California. As of December 31, 2000, we had total estimated proved reserves net of minority interest of 172 MMBOE, and a standardized measure of discounted future net cash flow, before income taxes, for total proved reserves of $583.1 million. Of these totals, the South Monagas Unit represented 98 MMBbls and $368.4 million, Geoilbent represented 33 MMBbls and $140.2 million, and Arctic Gas represented 41 MMBOE and $74.5 million. As of December 31, 2000, we had total assets of $286.4 million. For the year ended December 31, 2000, we had total revenues of $140.3 million, cash flows from operations, before working capital changes, of $47.3 million, EBITDA of $80.6 million and long-term debt of $213.0 million. For the year ended December 31, 1999, we had total revenues of $89.1 million, cash flows from operations, before working capital changes, of $6.7 million, EBITDA of $29.9 million and long-term debt of $264.6 million. We currently have significant debt principal obligations payable in 2003 ($108 million) and 2007 ($105 million). Our debt service requirements may restrict our ability to fund capital expenditures necessary to maximize the value of our assets. The debt levels may restrict our ability to borrow additional monies to fund asset growth or to provide financial flexibility. Additionally, our ability to meet our debt obligations and to reduce our level of debt depends on our future performance and crude oil and natural gas realizations. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. If we are unable to repay our debt at maturity out of cash on hand, we could attempt to refinance such debt, or repay such debt with the proceeds of an equity offering. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions and our value and performance at the time of such offering or other financing. We cannot assure you that any such offering or refinancing can be successfully completed. 4 4 MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS As a result of Benton's increased leverage and poor investment returns since 1998, 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 aimed at creating new stockholder value, we undertook several significant actions beginning in 2000, including: - Hired a new President and Chief Executive Officer, a new Senior Vice President and Chief Financial Officer and a new Vice President and General Counsel; - Reconstituted our Board of Directors with industry executives with proven experience in oil and natural gas operations, finance and international operations; - Redefined our strategic priorities to focus on value creation; - Initiated capital conservation steps and financial transactions to de-leverage the company and improve cash flow for reinvestment; - Undertook a comprehensive study of our core Venezuelan asset to attempt to enhance the value of its production, thus ultimately increasing cash flow and potentially extending its productive life. 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. 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 advisors, are conducting a comprehensive review of strategic alternatives, including, but not limited to, selling all or part of our existing assets in Venezuela and Russia, debt restructuring, some combination thereof, 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. OPERATING STRATEGY Our long-term strategy is to identify and access large resources of hydrocarbons in underexploited areas around the world that can be developed at low overall finding and operating costs and converted into proved reserves, production and value. To achieve this strategy, we must: - restore our financial flexibility by restructuring our balance sheet; - exploit our core assets in Venezuela and Russia; and - seek and exploit new oil and natural gas reserves. With respect to our core Venezuelan assets, we intend to maximize the value of production at the South Monagas Unit, rather than increase production at any cost. As part of our strategic shift in focus on the value of the barrels produced, we suspended the development drilling program for a period of approximately six months starting in January 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 123 MMBbls (98 MMBbls net to Benton) of proved reserves of oil in the fields. Our goal will be an accelerated development program with lower cost production, starting from the second half of 2001, rising to an expected level of up to between 31,000-33,000 Bbls of oil equivalent per day in less than two years. This is based on current internal operating and financial assumptions and also assumes that we do not enter into a transaction under which we sell a significant portion of our assets, as described in "Item 1. Business - Management, Operational and Financial Restrictions." In the first half of 2001, we will concentrate on improving the production from the existing 143 available wells in Venezuela. We achieved our goal of 30,000 barrels of oil per day in early January and in February production rose to over 33,000 BBls of oil per day. Currently, production (as of March 23, 2001) is 28,500 Bbls of oil per day which is expected to decline to between 25,000 and 26,000 barrels of oil per day by mid-year, then increase when the new development plan commences in the third quarter. We expect to average approximately 28,500 Bbls of oil per day for the first quarter of 2001. The 2001 Venezuela capital budget includes $13.5 million for the construction of a 31-mile oil pipeline with a capacity of 20,000 Bbls per day that will connect the Tucupita Field production facility with the Uracoa central processing unit. This is expected to reduce Tucupita Field operating costs over $2.50 per Bbl and improve the infrastructure network to allow the future, efficient development of the Bombal Field. Funding for construction of the pipeline was provided by two loans funded by a Venezuelan bank in March 2001 totaling $12.3 million. 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 5 years. The second loan, in the amount of 4.4 billion Venezuelan Bolivars 5 5 ($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 initial quarterly period is 16.5%. In Russia, Geoilbent produced an average of 10,500 Bbls of oil per day in 2000 and is currently producing (as of March 23, 2001) 15,000 Bbls of oil per day. In 2001, Geoilbent will concentrate on increasing production, building a natural gas pipeline to take flared natural gas to market and improving profitability. Geoilbent is self-funding and although it has not paid dividends to its shareholders in the past, the management of Geoilbent has informed us that it expects to pay a dividend to its shareholders beginning in 2001, including Benton Oil and Gas Company. However, any such action by Geoilbent would require the consent of at least one other Geoilbent shareholder and may be subject to other regulatory and contractual restrictions. Our plan for Arctic Gas includes continuing to expand production of oil and condensate through the recompletion of existing wells, building facilities and pipelines to optimize delivery of liquids and initiating the production and sale of natural gas in 2002. We intend to seek long-term contracts for oil, condensate and natural gas production in both export and domestic Russian markets. The goal at Arctic Gas is to preserve a controlling equity position and seek financial and technical partnerships to enable paced, large-scale development of the Samburg and Yevo-Yakha license blocks. Over the long-term, we intend to continue to seek and exploit new oil and natural gas reserves in current areas of interest while minimizing the associated financial and operating risks. To reduce these risks, not only in seeking new reserves but also with respect to our existing operations, we: - Focus Our Efforts in Areas of Low Geologic Risk: We intend to focus our exploration and development activities only in areas of known, proven hydrocarbons. - Use Proven Advanced Technology in Both Exploration and Development: We use 3-D seismic technology, which produces a three dimensional image of the earth's subsurface through the computer's interpretation of seismic data. This technology provides a more detailed understanding of the subsurface than conventional surveys, which contributes significantly to field appraisal, development and production. - Establish a Local Presence Through Joint Venture Partners and the Use of Local Personnel: We seek to establish a local presence in our areas of operation to facilitate stronger relationships with local government and labor. In addition, using local personnel helps us to take advantage of local knowledge and experience and to minimize costs. - Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time: We often agree to minimum capital expenditure or development commitments at the outset of new projects, but we endeavor to structure such commitments so that we can fulfill them over time, thereby limiting our initial cash outlay. In pursuing new opportunities, we will seek to enter at an early stage and find investment partners at the point of maximum value in an effort to reduce our risk in any one venture. We also will continue to assess project value regularly, preparing to monetize assets as opportunities arise. OPERATIONS The following table summarizes our proved reserves, drilling and production activity, and financial operating data by principal geographic area at and for each of the years ended December 31. All Venezuelan reserves are attributable to an operating service agreement between Benton-Vinccler and Petroleos de Venezuela, S.A. under which all mineral rights are owned by the Government of Venezuela. Geoilbent and Arctic Gas Company are accounted for under the equity method and have been included at their respective ownership interest in our consolidated financial statements. Our year end financial information contains results from our Russian operations based on a twelve-month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2000, 1999 and 1998 reflect results from Geoilbent for the twelve months ended September 30, 2000, 1999 and 1998, and from Arctic Gas for the twelve months ended September 30, 2000. We own 80 percent of Benton-Vinccler. The reserve information includes reserve information net of a 20 percent deduction for the minority interest in Benton-Vinccler. Drilling and production activity and financial data are reflected without deduction for minority interest. 6 6
BENTON-VINCCLER ----------------------- YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 1998 ---- ---- ---- (DOLLARS IN 000'S) RESERVE INFORMATION: Proved reserves (MBbls) ................................................. 98,431 107,969 110,268 Discounted future net cash flow attributable to proved reserves, before income taxes ......................................... $ 368,464 $ 521,346 $ 49,964 Standardized measure of future net cash flows ........................... $ 284,549 $ 380,865 $ 49,964 DRILLING AND PRODUCTION ACTIVITY: Gross wells drilled ..................................................... 26 2 16 Average daily production (Bbls) ......................................... 25,585 26,485 33,349 FINANCIAL DATA: Oil and natural gas revenues ............................................ $ 139,890 $ 89,060 $ 82,215 Expenses: Operating expenses and taxes other than on income ........................................................... 46,848 38,839 39,075 Depletion ............................................................... 15,708 14,732 30,274 Write-down of oil and gas properties .................................... -- -- 153,800 Income tax expense (benefit) ............................................ 19,768 3,822 (21,392) ---------- ---------- ---------- Total expenses ........................................................ 82,324 57,393 201,757 ---------- ---------- ---------- Results of operations from oil and natural gas producing activities ...................................... $ 57,566 $ 31,667 $ (119,542) ========== ========== ==========
We own 34 percent of Geoilbent, which we account for under the equity method. The following table presents our proportionate share of Geoilbent's proved reserves, drilling and production activity, and financial operating data for the twelve months ended September 30, 2000, 1999 and 1998.
GEOILBENT --------- YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 1998 ---- ---- ---- (DOLLARS IN 000'S) RESERVE INFORMATION: Proved reserves (MBbls) .................................................... 32,615 36,415 31,053 Discounted future net cash flow attributable to proved reserves, before income taxes ............................................ $140,160 $215,348 $49,546 Standardized measure of future net cash flows .............................. $114,725 $169,077 $43,248 DRILLING AND PRODUCTION ACTIVITY: Gross wells drilled ........................................................ 39 28 31 Average daily production (Bbls) ............................................ 3,945 3,975 2,530 FINANCIAL DATA: Oil and natural gas revenues ............................................... $ 25,202 $ 11,142 $ 8,059 Expenses: Operating expenses and taxes other than on income .............................................................. 9,548 4,274 4,445 Depletion .................................................................. 3,249 3,287 3,407 Write down of oil and gas properties ....................................... -- -- -- Income tax expense ......................................................... 3,215 442 9 -------- -------- ------- Total expenses ........................................................... 16,012 8,003 7,861 -------- -------- ------- Results of operations from oil and natural gas producing activities ......................................... $ 9,190 $ 3,139 $ 198 ======== ======== =======
As of December 31, 2000 and 1999, respectively, we owned, free of any sale and/or transfer restrictions, 29 percent and 24 percent of the equity interests in Arctic Gas, which we account for under the equity method. The following table presents our proportionate share, free of sale and transfer restrictions, of Arctic Gas's proved reserves, drilling and production activity, and financial operating data for the twelve months ended September 30, 2000 and 1999. Arctic Gas had no proved reserves or operating or financial activity attributable to our interests prior to the period ended September 30, 1999. 7 7
ARCTIC GAS COMPANY ------------------ YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 ---- ---- (DOLLARS IN 000'S) RESERVE INFORMATION: Proved reserves (MBOE) .................................................... 41,236 3,714 Discounted future net cash flow attributable to proved reserves, before income taxes ........................................... $ 74,517 $ 8,241 Standardized measure of future net cash flows ............................. $ 56,880 $ 6,836 DRILLING AND PRODUCTION ACTIVITY: Gross wells drilled ....................................................... -- -- Average daily production (BOE) ............................................ 1,154 -- FINANCIAL DATA: Oil and natural gas revenues .............................................. $ 889 $ -- Expenses: Operating expenses and taxes other than on income ............................................................. 604 -- Depletion ................................................................. 78 -- --------- --------- Total expenses .......................................................... 682 -- --------- --------- Results of operations from oil and natural gas producing activities ........................................ $ 207 $ -- ========= =========
SOUTH MONAGAS UNIT, VENEZUELA (BENTON-VINCCLER) GENERAL In July 1992, Benton and Venezolana de Inversiones y Construcciones Clerico, C.A., a Venezuelan construction and engineering company ("Vinccler"), signed a 20-year operating service agreement with Petroleo y Gas, S.A. ("PDVSA"), an affiliate of Petroleos de Venezuela, S.A. to reactivate and further develop the Uracoa, Tucupita and Bombal Fields. These fields comprise the South Monagas Unit. At that time, we were one of three foreign companies ultimately awarded an operating service agreement to reactivate existing fields by PDVSA. We were the first U.S. company since 1976 to be granted such an oil field development contract in Venezuela. The oil and natural gas operations in the South Monagas Unit are conducted by Benton-Vinccler, our 80 percent-owned subsidiary. The remaining 20 percent of the outstanding capital stock of Benton-Vinccler is owned by Vinccler. Through our majority ownership of stock in Benton-Vinccler, we make all operational and corporate decisions related to Benton-Vinccler, subject to certain super-majority provisions of Benton-Vinccler's charter documents related to: - mergers; - consolidations; - sales of substantially all of its corporate assets; - change of business; and - similar major corporate events. Vinccler has an extensive operating history in Venezuela. It provided Benton-Vinccler with initial financial assistance and significant construction services. Vinccler continues to provide ongoing assistance with governmental and labor relations. Under the terms of the operating service agreement, Benton-Vinccler is a contractor for PDVSA. Benton-Vinccler 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. In addition, PDVSA maintains full ownership of equipment and capital infrastructure following its installation. Benton-Vinccler invoices PDVSA each quarter based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted contract service fees per barrel. Benton-Vinccler receives its payments from PDVSA in U.S. dollars deposited directly into a U.S. bank account. The operating service agreement provides for Benton-Vinccler to receive an operating fee for each barrel of crude oil delivered. It also provides Benton-Vinccler with the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannot exceed the maximum total fee per barrel set forth in the agreement. The operating fee is subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. The maximum total fee is subject to quarterly adjustments to reflect changes in the average of certain world crude oil prices. Currently, we are in discussions with PDVSA regarding the appropriate amount to 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. 8 8 In December 1999, we entered into agreements with Schlumberger and Helmerich & Payne to further develop the Unit pursuant to a long term incentive based alliance program. The alliance program includes the drilling of up to 80 wells. It provides for financial incentives for Schlumberger and Helmerich & Payne that are intended to: - reduce drilling costs; - improve initial production rates of new wells; and - increase the average life of the downhole pumps at South Monagas. As part of Schlumberger's commitment to the program, it provides technical and engineering resources on-site full-time in Venezuela and at our offices in Carpinteria, California. We drilled 26 oil wells in 2000. As part of our strategic shift in focus on the value of the barrels produced, we suspended the development drilling program for a period of approximately six months starting in January 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 123 MMBbls (98 MMBbls net to Benton) of proved reserves of oil in the fields. Our goal will be an accelerated development program with lower cost production, starting from the second half of 2001, rising to an expected level of up to between 31,000-33,000 Bbls of oil equivalent per day in less than two years. This is based on current internal operating and financial assumptions and also assumes that we do not enter into a transaction under which we sell a significant portion of our assets, as described in "Item 1. Business - Management, Operational and Financial Restrictions.' In the first half of 2001, we will concentrate on improving the production from the existing 143 available wells in Venezuela. Production, currently (as of March 23, 2001) at 28,500 Bbls of oil per day in Venezuela, is expected to decline to between 25,000 and 26,000 Bbls of oil per day by mid-year, then increase when the new development plan starts in the third quarter. LOCATION AND GEOLOGY The Unit extends across the southeastern part of the state of Monagas and the southwestern part of the state of Delta Amacuro in eastern Venezuela. The Unit is approximately 51 miles long and eight miles wide and consists of 157,843 acres, of which the fields comprise approximately one-half. At December 31, 2000, proved reserves attributable to our Venezuelan operations were 123,039 MBbls (98,431 MBbls net to Benton). This represented approximately 57 percent of our proved reserves. Benton-Vinccler is primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 72 percent of the Unit's proved reserves. Benton-Vinccler has begun the development of the Tucupita and Bombal Fields, which contain the remaining 28 percent of the Unit's reserves. Benton-Vinccler is currently reinjecting the associated natural gas produced at Uracoa back into the reservoir. We are currently in discussions with PDVSA to sell the natural gas, although there is no assurance that any natural gas contracts will result from the discussions. DRILLING AND DEVELOPMENT ACTIVITY Benton-Vinccler contracts with third parties for drilling and completion of wells. In 2000, we drilled 26 wells. URACOA FIELD Benton-Vinccler has been developing the Unit since 1992, beginning with the Uracoa Field. During March 2001 (through March 23), a total of approximately 114 wells were producing an average of approximately 22,300 Bbls of oil per day in the Uracoa Field. The following table sets forth the Uracoa Field drilling activity and production information for each of the quarters presented: 9 9
WELLS DRILLED ------------- AVERAGE DAILY VERTICAL HORIZONTAL PRODUCTION FROM FIELD (Bbls) -------- ---------- ---------------------------- 1998: First Quarter .................................. - - 37,700 Second Quarter ................................. - - 32,600 Third Quarter .................................. 2 - 26,500 Fourth Quarter ................................. 3 3 25,900 1999: First Quarter .................................. - - 24,300 Second Quarter ................................. - - 22,800 Third Quarter .................................. - - 21,300 Fourth Quarter ................................. - - 21,000 2000: First Quarter .................................. 6 - 19,800 Second Quarter ................................. 9 1 20,500 Third Quarter .................................. 2 3 21,900 Fourth Quarter ................................. 2 3 23,100
Production rates began to decline in the fourth quarter of 1997 due to a reduction in drilling activity, natural reservoir decline, and production related problems. We ended drilling operations in the fourth quarter of 1997 because the initial development plan for the Uracoa Field was completed. Without continuous drilling, reservoirs like those at the Uracoa Field initially experience a sharp natural decline that decreases with time. This initial sharp natural decline was aggravated during 1998 due to the impact of production problems we experienced on certain wells and the degradation of the local electrical power source. We identified solutions to the electrical power and production related problems in 1998, but the installation of electrical power generation facilities and remediation work on wells was required into 1999. Additionally, we focused our efforts on the completion of a detailed geologic and reservoir simulation study during 1998, which identified up to 80 new infill and development well locations. Drilling resumed in the second half of 1998, but we suspended it again in 1999 due to uncertainties in oil prices and cash flows. We limited our capital expenditures during this period primarily to workovers and remediation activities. 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 oil wells in the Uracoa Field under the alliance agreements utilizing Schlumberger's technical and engineering resources. The 1998 geologic and reservoir simulation study indicated the viability of at least 80 additional primary infill wells in the Uracoa Field. Many of these new locations are in underdeveloped sands where the model was used to optimize well spacing and location. In the more developed areas of the field, we used the model to verify the economic viability of infill locations. In the first quarter of 2001, we began a comprehensive technical review of the South Monagas Unit that includes the completion of an extensive geologic and reservoir computer simulation study to optimize field management and the remaining development drilling program. The computer simulation study will update and extend the 1998 study on a portion of the Uracoa Field to the entire South Monagas Unit. It will incorporate all new geologic and reservoir information as well as the total production and drilling history from the more mature Uracoa Field and the underdeveloped Tucupita and Bombal Fields. We expect several benefits from the study including an optimum production profile of oil and gas, a revised water and natural gas injection strategy, more efficient development locations and improved well completion techniques. Since 1992, we have reactivated 15 previously drilled wells and drilled 142 new wells in the Uracoa Field using modern drilling and completion techniques that had not previously been utilized on the field. Of the new wells drilled, a total of 126 wells, or 89 percent, have been completed and placed on production, four of which were converted to injection wells. Additionally, six injection wells have been drilled, two of which have been converted to producing wells. We process the oil, water and natural gas we produce from the Uracoa Field in the Uracoa central processing unit. We ship the processed oil via pipeline to the PDVSA custody transfer point. We treat and filter produced water, and then re-inject it into the aquifer to assist the natural water drive. We re-inject natural gas into the natural gas cap for reservoir pressure maintenance. The major components of this state-of-the-art process facility were designed in the United States and installed by Benton-Vinccler. This process design is commonly used in heavy oil production in the United States, but was not previously used extensively in Venezuela to process crude oil of similar gravity or quality. The current production facility has capacity to handle 60 MBbls of oil per day, 130 MBbls of water per day, and 50 MMcf of natural gas per day. 10 10 In August 1999, Benton-Vinccler sold its recently-constructed power generation facility located in the Uracoa Field for $15.1 million. Concurrently with the sale, Benton-Vinccler entered into a long-term power purchase agreement with the purchaser of the facility to provide for the electrical needs of the field throughout the remaining term of the operating service agreement. Benton-Vinccler's 2001 capital expenditure budget includes drilling approximately 12 wells at an estimated cost of $16 million. Drilling additional wells will depend on the results of the current field development plan and reservoir computer study now underway, the results of the 2001 development drilling program and the availability of capital. TUCUPITA AND BOMBAL FIELDS Before becoming inactive in 1987, the Tucupita Field had been substantially developed. It had produced 67.1 MMBbls of oil, 34.7 MMBbls of water and 17.6 Bcf of natural gas. Benton-Vinccler drilled a successful pilot horizontal well in late 1996 to evaluate the remaining development potential of the Tucupita field. This well has produced 1.8 MMBbls of oil at an average rate of 1,117 Bbls of oil per day. The early success of this pilot horizontal well led to the drilling of a second horizontal well in 1998. Initial oil rates from the horizontal wells were encouraging, but water production soon increased sharply. As a result, we changed the redevelopment strategy to include drilling deviated wells to allow for more effective water shut-off. During the second half of 1998, we drilled five deviated infill wells to target undepleted portions of the field. All five wells encountered high oil saturations, with an average initial production rate of 922 Bbls of oil per day. Additionally, we re-activated nine wells, bringing production levels to 5,900 Bbls of oil per day. In 1999, Benton-Vinccler drilled a well on the west portion of the Tucupita Field to test the commercial viability of a previously undrilled fault block identified using 3-D seismic data. The well proved to be non-commercial for oil production; however, we will investigate the natural gas potential of this well. We are reinjecting produced water from Tucupita into the aquifer to aid the natural water drive, and we have been flaring the associated natural gas. However, this associated natural gas will be used to help generate electric power for the field in the first quarter of 2001. We are trucking the oil to the Uracoa central processing unit where we process the oil and ship it by pipeline to the custody transfer point. We have identified 18 new well locations in undepleted portions of the Tucupita Field. We anticipate additional viable wells once we complete a simulation study for Tucupita. Moreover, our analysis of petrophysical and production data has revealed significant behind-pipe recompletion potential in a deeper pay section that was not a primary target during the earlier development of the field. Currently, we have identified 14 wells with recompletion potential for reactivation. To date, we have drilled one well in the Bombal Field and reactivated another. The Bombal Field is currently producing 340 Bbls of oil per day. Our future plans include drilling up to 26 development wells and installing a processing facility to separate the oil, water and natural gas. Initially, we will re-inject the water and natural gas back into the reservoir. We are currently in discussions with PDVSA to sell the natural gas, although there are no assurances that gas contracts will result from these discussions. As a result of our analysis of the potential in the Tucupita field, and for environmental and safety reasons, we will begin construction of a $13.5 million, 31-mile, 20,000 Bbls per day capacity oil pipeline from Tucupita to the Uracoa central processing unit that we expect to complete in late 2001. Once completed, we would also use the pipeline to transport oil from the Bombal Field after the construction of a connecting pipeline estimated to cost $4.5 million. Currently, we are transporting crude oil by trucks from both Tucupita and Bombal. A pipeline would significantly reduce our transportation costs from both fields and allow us to produce increased volumes of oil more economically. CUSTOMERS AND MARKET INFORMATION Oil produced in Venezuela is delivered to PDVSA under the terms of an operating service agreement for an operating service fee. Benton-Vinccler has constructed a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA's storage facility. This is the custody transfer point. The service agreement specifies that the oil stream may contain no more than 1 percent base sediment and water. Quality measurements are conducted both at Benton-Vinccler's facilities and at PDVSA's storage facility. We are in the process of installing a continuous flow measuring unit at our facility so that we can closely monitor the quantities delivered to PDVSA. PDVSA provides Benton-Vinccler with a daily acknowledgment regarding the amount of oil accepted during the previous day. At the end of each quarter, Benton-Vinccler prepares an invoice to PDVSA for that quarter's deliveries. PDVSA pays the invoice at the end of the second month after the end of the quarter. Invoice amounts and payments are denominated in U.S. dollars. Payments are wire transferred into Benton-Vinccler's account in a commercial bank in the United States. Natural gas produced by Benton-Vinccler is currently re-injected or used for operations, although discussions to sell the natural gas to PDVSA have been initiated. There are no assurances that natural gas contracts will result from these discussions. 11 11 EMPLOYEES; COMMUNITY RELATIONS Benton-Vinccler seeks to employ nationals rather than bring expatriates into the country. Presently, there are six full-time expatriates working with Benton-Vinccler and 160 local employees. Benton-Vinccler also has conducted community relations programs, providing medical care, training, equipment and supplies, and support for local schools, in both states in which the unit is located. NORTH GUBKINSKOYE, RUSSIA (GEOILBENT) GENERAL In December 1991, the joint venture agreement forming Geoilbent was registered with the Ministry of Finance of the USSR. Geoilbent's ownership is as follows: - Benton owns 34 percent; - Purneftegazgeologia owns 33 percent; and - Purneftegaz owns 33 percent. In November 1993, the agreement was registered with the Russian Agency for International Cooperation and Development. Geoilbent was later re-chartered as a limited liability company. We believe that we have developed a good relationship with our co-founding shareholders and have not experienced any disagreements on major operational matters. Geoilbent may only take action through a 67 percent majority vote of its shareholders. LOCATION AND GEOLOGY Geoilbent develops, produces and markets crude oil from the North Gubkinskoye Field in the West Siberia region of Russia, located approximately 2,000 miles northeast of Moscow. 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. It is surrounded by large proven fields. The field is a large anticlinal structure with multiple pay sands. The development to date has focused on the BP 8, 9, 10, 11 and 12 reservoirs with minor development in the BP 6 and 7 reservoirs. Geoilbent is currently flaring the produced natural gas in accordance with environmental regulations, although it is exploring alternatives to market the natural gas. Geoilbent also holds rights to three more license blocks comprising 1,189,757 acres. DRILLING AND DEVELOPMENT ACTIVITY Geoilbent commenced initial operations in the field during the third quarter of 1992 with the construction of a 37-mile oil pipeline and installation of temporary production facilities. During March 2001 (through March 23), approximately 103 wells were producing an average of approximately 15,000 Bbls of oil per day. The following table sets forth drilling activity and production information for each of the quarters presented:
AVERAGE DAILY WELLS DRILLED PRODUCTION FROM FIELD (Bbls) ------------- ---------------------------- 1998: First Quarter............................ 10 7,600 Second Quarter........................... 9 8,600 Third Quarter............................ 7 9,900 Fourth Quarter........................... 5 9,900 1999: First Quarter............................ 5 10,500 Second Quarter........................... 6 11,400 Third Quarter............................ 8 13,000 Fourth Quarter........................... 9 13,200 2000: First Quarter............................ 2 11,200 Second Quarter........................... 12 12,700 Third Quarter............................ 15 13,900 Fourth Quarter........................... 10 14,700
Production was constrained in the first quarter of 2000 due to damage to production facilities resulting from a fire. 12 12 Geoilbent contracts with third parties for drilling and completion of wells. To date, 38 previously drilled wells have been reactivated and 153 wells have been drilled in the field. A total of 129 wells, or 84 percent, have been completed and placed on production, 20 of which were converted to water injection wells. Each well is drilled to an average measured depth of approximately 9,000 feet and an average true vertical depth of 8,000 feet. The current production facilities are operating at or near capacity and will need to be expanded to accommodate production increases. Geoilbent transports oil produced from the North Gubkinskoye Field to production facilities constructed and owned by Geoilbent. It then transfers the oil to Geoilbent's 37-mile pipeline which transports the oil from the North Gubkinskoye Field south to the main Russian oil pipeline network. Geoilbent has obtained financing through a $65 million parallel loan facility for the development of the North Gubkinskoye Field from the European Bank for Reconstruction and Development and the International Moscow Bank. A total of $48.5 million has been advanced to date from the loan facility. Geoilbent has a 2001 budget which includes capital expenditures of approximately $39 million, of which $28 million would be used to drill 55 wells in the North Gubkinskoye Field and $11 million would be used for construction of production and other facilities. Its budget also includes $11 million for principal payments on the loan facility. This budget is expected to be funded from Geoilbent's cash flow from operations. CUSTOMERS AND MARKET INFORMATION Geoilbent's 37-mile pipeline runs from the field to the main pipeline in the area where Geoilbent transfers the oil to Transneft, the state oil pipeline monopoly. Transneft then transports the oil to the western border of Russia for export sales or to various domestic locations for non-export sales. Trading companies such as Rosneffegasexport handle all export oil sales. All export sales have been paid in U.S. dollars into Geoilbent's account in Moscow. Domestic sales are paid in Russian Rubles. During 2000, Geoilbent sold approximately 48 percent of its production in the export market and 52 percent in the domestic market. EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS Geoilbent employs Russian nationals almost exclusively. Presently, there are two full-time expatriates working with Geoilbent and 603 local employees. We have conducted community relations programs, providing medical care, training, equipment and supplies in towns in which Geoilbent personnel reside and also for the nomadic indigenous population which reside in the area of oilfield operations. EAST URENGOY, RUSSIA (ARCTIC GAS COMPANY) GENERAL Arctic Gas Company, formerly Severneftegaz, was formed in 1992 as a private company to explore and develop the Samburg and Yevo-Yakha License Blocks. The Samburg and Yevo-Yakha License Blocks are located within the West Siberian Basin, the world's largest sedimentary basin, which contains nearly one third of the world's proved and probable natural gas reserves. Both license blocks occur on the eastern flank of the giant Urengoy natural gas field, which currently produces hydrocarbons from Cenomanian reservoirs. Under the terms of agreements signed in April 1998, we acquired a 40 percent interest in Arctic Gas in return for providing or arranging up to $100 million of credit financing for the project. Our agreements impose restrictions on the sale and transfer of these shares subject to disbursements under the credit financing and provide that for every $2.5 million of credit made available, 1 percent of the interest will be released from the restrictions. As of December 31, 2000, we had provided $22.0 million of credit, all of which had been applied to the release of restrictions on the shares. As a result, we had earned the right to remove restrictions from shares representing an approximate 9 percent equity interest. From 1998 through December 2000, we separately purchased shares representing an additional 20 percent equity interest not subject to any sale or transfer restrictions. Including the additional purchased shares, as of December 31, 2000, we owned a total of 60 percent of the voting shares of Arctic Gas, of which 29 percent was not subject to restrictions. 13 13 The following table summarizes our ownership interests of Arctic Gas Company:
AS OF DECEMBER 31, ------------------ 2000 1999 ---- ---- Shares released from restrictions 9% 5% Additional purchased shares 20% 19% --------- ---------- Total shares not subject to restrictions 29% 24% Shares subject to restrictions 31% 35% --------- ---------- Total ownership 60% 59% ========= ==========
LOCATION AND GEOLOGY The Samburg and Yevo-Yakha License Blocks comprise 794,972 acres and are situated approximately 150 miles north of Geoilbent in the Yamal-Nenets Autonomous Region of Russia. The towns and communities of Novy Urengoy, Samburg, Urengoy and Nyda are located near the two licenses. Extensive exploration drilling and testing (over 90 wells) on the Samburg and Yevo-Yakha licenses has resulted in the discovery of major resources of natural gas, condensate and oil. The primary reservoirs of these fields are currently being produced in both the adjacent Urengoy Field and Rospan Block. Historic production at the Urengoy Field is now on decline, and the undeveloped reserves discovered on the adjacent Arctic Gas and Rospan Blocks may be of interest to Gazprom and Russia as replacement for the production that is being lost at Urengoy. DRILLING AND DEVELOPMENT ACTIVITY Arctic Gas has reactivated six previously drilled oil wells through March 23, 2001. We are trucking oil to storage facilities where it is collected for sale. Arctic Gas is currently producing approximately 2,300 Bbls of oil per day. The following table sets forth reactivation activity and production information for each of the quarters presented:
AVERAGE DAILY WELLS REACTIVATED PRODUCTION FROM FIELD (Bbls) ----------------- ---------------------------- 1999: Fourth Quarter.................................... 1 - 2000: First Quarter..................................... - 400 Second Quarter.................................... 2 940 Third Quarter..................................... 1 1,500 Fourth Quarter.................................... 1 1,700
Arctic Gas is currently planning for a Samburg oil and natural gas pilot development project. The pilot project calls for: - drilling new wells; - installing natural gas processing facilities; and - connecting into the export pipeline system. The Arctic Gas blocks are located in the heart of the Urengoy/Yamburg producing and support infrastructure region and are well situated for development. Natural gas export trunklines are located 11 kilometers from the blocks. Arctic Gas and Gazprom have entered into preliminary agreements to allow access to existing oil, liquids and natural gas pipelines and facilities that could potentially result in product sales to domestic and export markets. Arctic Gas is in discussions with various parties concerning the export of natural gas, although there are no assurances that contracts will result from these discussions. Gazprom has granted Arctic Gas access to its transportation system beginning in the third quarter of 2001 for natural gas sales from the blocks to certain customers in the former Soviet Union. Further development activities are subject to the pace and scope of Arctic Gas's internally generated funds and to our ability to provide or arrange further funding. 14 14 EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS Arctic Gas is a Russian company that employs Russian nationals almost exclusively. Presently, there are two full-time expatriates working with Arctic Gas and 111 local employees. We have conducted community relations programs in Russia, providing medical care, training, equipment and supplies in towns in which Arctic Gas personnel reside and also for the nomadic indigenous population which reside in the area of oilfield operations. WAB-21, SOUTH CHINA SEA (BENTON OFFSHORE CHINA COMPANY) GENERAL 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, 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. LOCATION AND GEOLOGY The WAB-21 contract area is located approximately 50 miles southeast of the Dai Hung (Big Bear) Oil Field. The block is adjacent to British Petroleum's giant natural gas discovery at Lan Tay (Red Orchid) and 100 miles north of Exxon's Natuna Discovery. The contract area covers several similar structural trends, each with potential for hydrocarbon reserves in possible multiple pay zones. The contract area is located northwest of Zengmu Basin (Offshore Sarawak), where two Chinese institutions have already conducted geophysical seismic surveys. Based on the multi-disciplinary data available from Zengmu Basin to the southeast, East Natuna Basin to the south and southwest, and WAN'AN (Con Son) Basin to the west and northwest, there is substantial evidence of hydrocarbon potential in the contract area. DRILLING AND DEVELOPMENT ACTIVITY Due to the sovereignty issues, we have been unable to pursue an exploration program during phase one of the contract. As a result, we have obtained extensions, with the current extension in effect until June 2001. We expect extensions to continue to be available to us. China and Vietnam are now engaged in discussions to resolve the territorial dispute, although there is no certainty of timing or the outcome of such discussions. Once there has been a resolution of the disputes, an exploration program will commence including the acquisition of 2-D seismic data as required by the petroleum contract with CNOOC. DOMESTIC OPERATIONS 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. We 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 1999, we drilled the 2199 #7 exploratory well to the Gaviota anticline. Drill stem tests proved to be inconclusive or non-commercial, and we temporarily abandoned the well for further evaluation. In November 1999, 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. In April 2000, we entered into a retainer agreement, and in May 2000 an exploration agreement, with Coastline Energy Corporation. The purpose of these agreements was to acquire, explore and develop oil and natural gas prospects both onshore and in the state waters of the 15 15 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 on: - oil and natural gas production acquired or developed; and - 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 Bbls 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 cash and a 5 percent carried working interest in up to four wells that may be drilled in the future. RESERVES Estimates of our proved reserves as of December 31, 2000 were prepared by Ryder Scott Company, LP, independent petroleum engineers. In prior years, reserve estimates were prepared by us and audited by Huddleston & Co., Inc., independent petroleum engineers. The following table sets forth information regarding estimates of proved reserves at December 31, 2000. The Venezuelan information includes reserve information net of a 20 percent deduction for the minority interest in Benton-Vinccler. All Venezuelan reserves are attributable to an operating service agreement between Benton-Vinccler and PDVSA, under which all mineral rights are owned by the Government of Venezuela. Although we estimate that there are substantial natural gas reserves in the Benton-Vinccler properties in Venezuela and the license blocks held by Geoilbent, no natural gas reserves have been recorded as of December 31, 2000 because of a lack of sales and/or transportation contracts in place. Natural gas proved reserves have been recognized for Arctic Gas, which has transportation and marketing contracts in place. Geoilbent and Benton-Vinccler are currently considering alternatives to market the natural gas.
NET CRUDE OIL AND CONDENSATE (MBbls) PROVED PROVED DEVELOPED UNDEVELOPED TOTAL ---------- ------------ -------- Venezuela ............................................. 53,774 44,657 98,431 Geoilbent ............................................. 14,913 17,702 32,615 Arctic Gas(1) ......................................... 2,325 13,495 15,820 -------- -------- -------- Total ......................................... 71,012 75,854 146,866 ======== ======== ======== NET NATURAL GAS (MMcf) ---------------------- PROVED PROVED DEVELOPED UNDEVELOPED TOTAL ---------- ----------- ------ Arctic Gas(1) 17,801 134,695 152,496 ======== ======== ========
(1) Based on 29 percent ownership not subject to restrictions as of December 31, 2000. Estimates of commercially recoverable oil and natural gas reserves and of the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, such as: - historical production from the subject properties; - comparison with other producing properties; - the assumed effects of regulation by governmental agencies; and - assumptions concerning future operating costs, severance and excise taxes, export tariffs, abandonment costs, development costs and workover and remedial costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and various classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the commercially recoverable reserves of oil attributable to any particular property or group of properties, the classification, cost and risk of recovering such reserves and estimates of the future net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times may vary substantially. The difficulty of making precise estimates is accentuated by the fact that 57 percent of our total proved reserves were undeveloped as of December 31, 2000. 16 16 Therefore, the following costs will likely vary from our estimates and such variances may be material: - actual production; - oil sales; - severance and excise taxes;, - export tariffs; - development expenditures; - workover and remedial expenditures; - abandonment expenditures; and - operating expenditures. Reserve estimates are not constrained by the availability of the capital resources required to finance the estimated development and operating expenditures. In addition, actual future net cash flows will be affected by factors such as: - actual production; - supply and demand for oil; - availability and capacity of gathering systems and pipelines; - changes in governmental regulations or taxation; and - the impact of inflation on costs. The timing of actual future net oil sales from proved reserves, and thus their actual present value, can be affected by the timing of the incurrence of expenditures in connection with development of oil and gas properties. The 10 percent discount factor, which is required by the SEC to be used to calculate present value for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the oil and natural gas industry. Discounted present value, no matter what discount rate is used, is materially affected by assumptions as to the amount and timing of future production, which assumptions may and often do prove to be inaccurate. For the period ending December 31, 2000, we reported $583.1 million of discounted future net cash flows before income taxes from proved reserves based on the SEC's required calculations. PRODUCTION, PRICES AND LIFTING COST SUMMARY In the following table we have set forth by country our net production, average sales prices and average lifting costs for the years ended December 31, 2000, 1999 and 1998. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership) and Arctic Gas (29 percent, 24 percent and 10 percent ownership not subject to any sale or transfer restrictions at December 2000, 1999 and 1998, respectively), which are accounted for under the equity method, have been included at their respective ownership interest in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, our results of operations for the years ended December 31, 2000, 1999 and 1998 reflect results from Geoilbent for the twelve months ended September 30, 2000, 1999 and 1998, and from Arctic Gas for the twelve months ended September 30, 2000.
YEARS ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ---- ---- ---- VENEZUELA Net Crude Oil Production (Bbls)......... 9,364,088 9,666,958 12,172,352 Average Crude Oil Sales Price ($ per Bbl) $ 14.94 $9.21 $6.75 Average Lifting Costs ($ per Bbl)...... $ 5.01 $4.02 $3.21 GEOILBENT Average Crude Oil Production (Bbls)..... 1,444,181 1,451,000 923,602 Average Crude Oil Sales Price ($ per Bbl) $ 17.45 $7.68 $8.72 Average Lifting Costs ($ per Bbl)...... $ 7.03 $3.41 $6.09 ARCTIC GAS Net Crude Oil Production (Bbls)......... 48,833 - - Average Crude Oil Sales Price ($ per Bbl) $ 18.20 - - Average Lifting Costs ($ per Bbl)...... $ 12.99 - -
17 17 REGULATION GENERAL 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; - limitations on oil and natural gas production; - tax and other laws relating to the petroleum industry; o changes in such laws; and - changes in administrative regulations and the interpretation 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 costs. In any country in which we may do business, the oil and natural gas industry legislation and agency regulation is periodically changed for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business. VENEZUELA Venezuela requires environmental and other permits for certain operations conducted in oil field development, such as site construction, drilling, and seismic activities. As a contractor to PDVSA, Benton-Vinccler submits capital and operating budgets to PDVSA for approval. Capital expenditures to comply with Venezuelan environmental regulations relating to the reinjection of natural gas in the field and water disposal were $1.1 million in 2000 and are expected to be $2.5 million in 2001. Benton-Vinccler also submits requests for permits for drilling, seismic and operating activities to PDVSA, which then obtains such permits from the Ministry of Energy and Mines and Ministry of Environment, as required. Benton-Vinccler is also subject to income, municipal and value-added taxes, and must file certain monthly and annual compliance reports to the national tax administration and to various municipalities. RUSSIA Geoilbent and Arctic Gas submit annual production and development plans, which include information necessary for permits and approvals for their planned drilling, seismic and operating activities, to local and regional governments and to the Ministry of Fuel and Energy and the Ministry of Natural Resources. They also submit annual production targets and quarterly export nominations for oil pipeline transportation capacity to the Ministry of Fuel and Energy. Geoilbent and Arctic Gas are subject to customs, value-added, and municipal and income taxes. Various municipalities and regional tax inspectorates are involved in the assessment and collection of these taxes. Geoilbent and Arctic Gas must file operating and financial compliance reports with several agencies, including the Ministry of Fuel and Energy, Ministry of Natural Resources, Committee for Technical Mining Monitoring and the State Customs Committee. 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 increased to 34 Euros per ton (approximately $3.80 per barrel) on November 3, 2000 from 15 Euros per ton in 1999. We are unable to predict the impact of taxes, duties and other burdens in the future for our Russian operations. DRILLING, ACQUISITION AND FINDING COSTS From commencement of operations through December 31, 2000, we added, net of production and property sales, approximately 171.5 MMBOE of proved reserves through purchases of reserves-in-place, discoveries of oil and natural gas reserves, extensions of existing producing fields and revisions of previously estimated reserves, for which the finding costs were $2.13 per BOE. Our estimate of future development costs for our undeveloped proved reserves at December 31, 2000 was $1.90 per BOE. The estimated future development costs are based upon our anticipated cost of developing our non-producing proved reserves, which costs are calculated using historical costs for similar activities. 18 18 For acquisitions of leases and producing properties, development and exploratory drilling, production facilities and additional development activities such as workovers and recompletions, we spent approximately (excluding our share of capital expenditures incurred by equity affiliates): - $ 50 million during 2000; - $ 33 million during 1999; and - $ 94 million during 1998. We have drilled or participated in the drilling of wells as follows:
YEARS ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ---- ---- ---- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- WELLS DRILLED: Exploratory: Crude oil................................. - - - - - - Natural gas............................... - - - - - - Dry holes................................. - - 3 1.60 - - Development: Crude oil................................. 65 34.06 28 9.18 46 22.54 Natural gas............................... - - - - - - Dry holes................................. - - - - - - ------ --------- ------ -------- ------ ------- TOTAL................................ 65 34.06 31 10.78 46 22.54 ====== ========= ====== ======== ====== ======= AVERAGE DEPTH OF WELLS (FEET).................. 7,048 9,092 7,934 PRODUCING WELLS(1): Crude Oil................................. 268 163.55 181 108.00 159 97.30 Natural Gas............................... - - - - - -
(1) The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired. At December 31, 2000, we were participating in the drilling of five wells in Russia. All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not own any drilling equipment. ACREAGE The following table summarizes the developed and undeveloped acreage that we owned, leased or had under concession as of December 31, 2000:
DEVELOPED UNDEVELOPED GROSS NET GROSS NET Venezuela(1) ........................ 9,748 7,798 673,390 276,065 Russia(2) ........................... 41,936 13,965 2,109,879 677,109 China ............................... - - 7,470,080 7,470,080 United States ....................... - - 15,874 13,718 -------- -------- ---------- --------- Total ...................... 51,684 21,763 10,269,223 8,436,972 ======== ======== ========== =========
(1) Venezuela includes 525,295 gross acres related to our Delta Centro project, which was in the process of being abandoned at December 31, 2000. (2) Russia includes 794,972 gross acres related to Arctic Gas, which is included based on a 29 percent ownership interest. 19 19 COMPETITION We encounter strong competition from major oil and gas companies and independent operators in acquiring properties and leases for exploration for crude oil and natural gas. The principal competitive factors in the acquisition of such oil and gas properties include the staff and data necessary to identify, investigate and purchase such leases, and the financial resources necessary to acquire and develop such leases. Many of our competitors have financial resources, staffs and facilities substantially greater than ours. EMPLOYEES AND CONSULTANTS At December 31, 2000, we had 52 full-time employees, augmented from time-to-time with independent consultants, as required. Benton-Vinccler had 160 employees, Geoilbent had 603 employees and Arctic Gas had 111 employees. TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE All Venezuelan reserves are attributable to an operating service agreement between Benton-Vinccler and PDVSA, under which all mineral rights are owned by the Government of Venezuela. With regard to Russian acreage, Geoilbent and Arctic Gas have obtained certain documentation from appropriate regulatory agencies in Russia which we believe is adequate to establish their right to develop, produce and market oil and natural gas from their fields. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for another 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 territorial dispute has existed for many years, and there has been limited exploration and no development activity in the area under dispute. It is uncertain when or how this dispute will be resolved, and under what terms the various countries and parties to the agreements may participate in the resolution, although certain proposed economic solutions currently under discussion would result in our interest being reduced. As is customary in the oil and natural gas industry, we make a limited review of title to farmout acreage and to undeveloped U.S. oil and natural gas leases upon execution of the contracts and leases. Prior to the commencement of drilling operations, a thorough drillsite title examination is conducted and curative work is performed with respect to significant defects. We follow the practice of obtaining title opinions on our domestic producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and natural gas industry. Our oil and natural gas properties are subject to customary royalty interests, liens for current taxes, and other burdens which we believe do not materially interfere with the use of or affect the value of such properties. 20 20 GLOSSARY When the following terms are used in the text they have the meanings indicated. MCF. "Mcf" means thousand cubic feet. "Mmcf" means million cubic feet. "Bcf" means billion cubic feet. "Tcf" means trillion cubic feet. BBL. "Bbl" means barrel. "Bbls" means barrels. "MBbls" means thousand barrels. "MMBbls" means million barrels. "BBbls" means billion barrels. BOE. "BOE" means barrels of oil equivalent, which are determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas so that six Mcf of natural gas is referred to as one barrel of oil equivalent or "BOE". "MBOE" means thousands of barrels of oil equivalent. "MMBOE" means millions of barrels of oil equivalent. CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with exploratory and development drilling (including exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological, geophysical and land-related overhead expenditures; delay rentals; producing property acquisitions; and other miscellaneous capital expenditures. COMPLETION COSTS. "Completion Costs" means, as to any well, all those costs incurred after the decision to complete the well as a producing well. Generally, these costs include all costs, liabilities and expenses, whether tangible or intangible, necessary to complete a well and bring it into production, including installation of service equipment, tanks, and other materials necessary to enable the well to deliver production. DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional well to the same reservoir as other producing wells on a lease, or drilled on an offset lease not more than one location away from a well producing from the same reservoir. EXPLORATORY WELL. An "Exploratory Well" is a well drilled in search of a new and as yet undiscovered pool of oil or natural gas, or to extend the known limits of a field under development. FINDING COST. "Finding Cost", expressed in dollars per BOE, is calculated by dividing the amount of total capital expenditures related to acquisitions, exploration and development costs (reduced by proceeds for any sale of oil and gas properties) by the amount of total net reserves added or reduced as a result of property acquisitions and sales, drilling activities and reserve revisions during the same period. FUTURE DEVELOPMENT COST. "Future Development Cost" of proved nonproducing reserves, expressed in dollars per BOE, is calculated by dividing the amount of future capital expenditures related to development properties by the amount of total proved non-producing reserves associated with such activities. GROSS ACRES OR WELLS. "Gross Acres or Wells" are the total acres or wells, as the case may be, in which an entity has an interest, either directly or through an affiliate. LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a producing formation to the surface, consisting of the costs incurred to operate and maintain wells and related equipment and facilities, including labor costs, repair and maintenance, supplies, insurance, production, severance and windfall profit taxes. NET ACRES OR WELLS. A party's "Net Acres" or "Net Wells" are calculated by multiplying the number of gross acres of gross wells in which that party has an interest by the fractional interest of the party in each such acre or well. PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved Developed Reserves expected to be produced from existing completion intervals now open for production in existing wells. "Producing Properties" are properties to which Producing Reserves have been assigned by an independent petroleum engineer. 21 21 PROVED DEVELOPED RESERVES. "Proved Developed Reserves" are Proved Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. PROVED RESERVES. "Proved Reserves" are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and natural gas reservoirs under existing economic and operating conditions, that is, on the basis of prices and costs as of the date the estimate is made and any price changes provided for by existing conditions. PROVED UNDEVELOPED RESERVES. "Proved Undeveloped Reserves" are Proved Reserves which can be expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. RESERVES. "Reserves" means crude oil and natural gas, condensate and natural gas liquids, which are net of leasehold burdens, are stated on a net revenue interest basis, and are found to be commercially recoverable. ROYALTY INTEREST. A "Royalty Interest" is an interest in an oil and gas property entitling the owner to a share of oil and natural gas production (or the proceeds of the sale thereof) free of the costs of production. STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS. The "Standardized Measure of Future Net Cash Flows" is a method of determining the present value of Proved Reserves. The future net oil sales from Proved Reserves are estimated assuming that oil and natural gas prices and production costs remain constant. The resulting stream of oil sales is then discounted at the rate of 10 percent per year to obtain a present value. 3-D SEISMIC. "3-D Seismic" is the method by which a continuous three dimensional image of the earth's subsurface is created through the interpretation of seismic data. 3-D surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production. 2-D SEISMIC. " 2-D Seismic" is the method by which discreet two-dimensional profiles of the earth's subsurface are interpreted and interpolated to provide a basic understanding of the subsurface. UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and natural gas acreage on which wells have not been drilled or completed to a point that would permit commercial production regardless of whether such acres contain proved reserves. ITEM 2. PROPERTIES 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 separate building for approximately $76,000 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 $50,000 per month. ITEM 3. LEGAL PROCEEDINGS On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the United States Bankruptcy Court, Western District of Louisiana against us and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas of Louisiana. The suit seeks a determination that the sale by BOGLA to Tesla Resources Corporation, a wholly owned subsidiary of WRT Energy Corporation, of certain West Cote Blanche Bay properties for $15.1 million, constituted a fraudulent conveyance under 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 have been filed. We believe that this case lacks merit and that an unfavorable outcome is unlikely. In 1996, 1997 and November 1998, we made certain 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. At December 31, 1997, the aggregate outstanding amounts of the loans were $2.0 million. At September 30, 1998, the aggregate outstanding amounts of the loans were $4.4 million. In the fourth quarter of 1998,we loaned Mr. Benton an additional $1.1 million. The proceeds of the loan were to be used to pay in full certain margin account obligations owed to third parties which had obtained a pledge from Mr. Benton of his shares of Benton stock. We then obtained a security interest in those shares of stock, certain 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 22 22 the decline in the price of Benton stock. As a result, we recorded an allowance for doubtful accounts of $2.9 million. The portion of the note secured by Benton stock and stock options, $2.1 million, was presented on our balance sheet as a reduction from stockholders' equity at December 31, 1998. In August 1999, Mr. Benton filed a Chapter 11 (reoganization) 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. 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 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 first half of 2001, we will retain our security interest in Mr. Benton's 600,000 shares of Benton stock and in his stock options, and in a portion of certain proceeds of his Consulting Agreement. Repayment of any amounts of these loans by Mr. Benton will be achieved through Mr. Benton's liquidation of certain real and personal property assets; a phased liquidation of Benton stock resulting from Mr. Benton's exercise of his Benton stock options; and, if necessary, from the retained interest in the portion of the Consulting Agreement's proceeds. The amount we eventually realize and the timing of our receipt of payments will depend upon the timing and results of the liquidation of Mr. Benton's assets, including Benton Oil and Gas Company stock. In the normal course of our business, there are various other legal proceedings outstanding. In the opinion of management, these proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS During the three month period ended December 31, 2000, no matter was submitted to a vote of security holders. 23 23 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY Our Common Stock has traded on the New York Stock Exchange ("NYSE") since April 29, 1997 under the symbol "BNO." As of December 31, 2000, there were 33,821,919 shares of Common Stock outstanding held of record by approximately 962 stockholders. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE. YEAR QUARTER HIGH LOW - -------------- -------------------------- ------------ ------------ 1999 First quarter $5.19 $1.94 Second quarter 4.38 1.88 Third quarter 3.13 1.50 Fourth quarter 2.75 1.44 2000 First quarter 4.50 1.56 Second quarter 3.56 2.00 Third quarter 3.19 1.94 Fourth quarter 2.75 1.38 On March 28, 2001, the last sales price for the Common Stock as reported by NYSE was $2.00 per share. Our policy is to retain earnings to support the growth of our business. Accordingly, our Board of Directors has never declared cash dividends on our Common Stock, and our indentures currently restrict the declaration and payment of any cash dividends. 24 24 ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA SELECTED CONSOLIDATED FINANCIAL DATA The following table sets forth our selected consolidated financial data for each of the years in the five year period ended December 31, 2000. The selected consolidated financial data have been derived from, and should be read in conjunction with our annual audited consolidated financial statements, including the notes thereto. Our year end financial information contains results from our Russian operations based on a twelve month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2000, 1999 and 1998 reflect results from Geoilbent for the twelve months ended September 30, 2000, 1999 and 1998, and from Arctic Gas for the twelve months ended September 30, 2000 and 1999.
YEARS ENDED DECEMBER 31, ------------------------ 2000 1999 1998 1997 1996 --------- --------- --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENTS OF OPERATIONS: Total revenues ..................................................... $ 140,284 $ 89,060 $ 82,212 $ 154,033 $ 138,656 Operating expenses ................................................. 47,430 39,393 40,066 35,184 18,069 Depletion, depreciation and amortization ........................... 17,175 16,519 33,157 44,513 31,778 Write-downs of oil and gas properties and impairments ................................................ 1,346 25,891 193,893 - - General and administrative expenses ................................ 16,739 25,969 21,485 17,676 15,139 Taxes other than on income ......................................... 4,390 3,813 3,677 5,361 3,130 --------- --------- --------- --------- --------- Operating income (loss) ............................................ 53,204 (22,525) (210,066) 51,299 70,540 Investment income and other ........................................ 8,559 8,986 13,982 12,594 7,281 Interest expense ................................................... (28,973) (29,247) (32,007) (24,082) (15,578) Net gain on exchange rates ......................................... 326 1,044 1,767 2,011 1,831 Partnership exchange expenses ...................................... - - - - (2,140) Gain on sale of properties ......................................... - - - - 7,175 --------- --------- --------- --------- --------- Income (loss) from consolidated companies before income taxes and minority interests ............................ 33,116 (41,742) (226,324) 41,822 69,109 Income tax expense (benefit) ....................................... 14,032 (7,526) (24,911) 16,620 19,922 --------- --------- --------- --------- --------- Income (loss) before minority interests ............................ 19,084 (34,216) (201,413) 25,202 49,187 Minority interest in consolidated subsidiary Companies ...................................................... 7,869 937 (22,895) 6,333 9,984 --------- --------- --------- --------- --------- Income (loss) from consolidated companies .......................... 11,215 (35,153) (178,518) 18,869 39,203 Equity in net earnings (losses) of affiliate companies (2) ......... 5,313 2,869 (5,062) (820) (846) --------- --------- --------- --------- --------- Income (loss) before extraordinary items ........................... 16,528 (32,284) (183,580) 18,049 38,357 Extraordinary income (expense) ..................................... 3,960 - - - (10,075) --------- --------- --------- --------- --------- Net income (loss) .................................................. $ 20,488 $ (32,284) $(183,580) $ 18,049 $ 28,282 ========= ========= ========= ========= ========= Net income (loss) per common share : Basic: Income (loss) before extraordinary items .................... $ 0.54 ($ 1.09) ($ 6.21) $ 0.62 $ 1.42 Extraordinary items ......................................... 0.13 - - - (0.38) --------- --------- --------- --------- --------- Net income (loss) ........................................... $ 0.67 ($ 1.09) ($ 6.21) $ 0.62 $ 1.04 ========= ========= ========= ========= ========= Diluted: Income (loss) before extraordinary items .................... $ 0.53 ($ 1.09) ($ 6.21) $ 0.59 $ 1.29 Extraordinary items ......................................... 0.13 - - - (0.34) --------- --------- --------- --------- --------- Net income (loss) ........................................... $ 0.66 ($ 1.09) ($ 6.21) $ 0.59 $ 0.95 ========= ========= ========= ========= ========= Weighted average common shares outstanding Basic .......................................................... 30,724 29,577 29,554 29,119 27,088 Diluted ........................................................ 30,890 29,577 29,554 30,834 29,813
25 25
AT DECEMBER 31, --------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- BALANCE SHEET DATA: Working capital ................................... $ 12,370 $ 32,093 $ 60,927 $174,759 $106,051 Total assets ...................................... 286,447 276,311 324,363 573,599 425,810 Long-term obligations, net of current position .... 213,000 264,575 280,002 280,016 175,028 Stockholders' equity (deficit)(1) ................. 12,904 (17,178) 12,989 197,732 174,899
(1) No cash dividends were paid during the periods presented. (2) As discussed in Note 1 to the Financial Statements, in 1999 we changed our method of reporting our investment in Geoilbent. 26 26 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS As a result of our increased leverage and poor investment returns since 1998, 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 aimed at creating new stockholder value, we undertook several significant actions beginning in 2000, including: - Hired a new President and Chief Executive Officer, a new Senior Vice President and Chief Financial Officer and a new Vice President and General Counsel; - Reconstituted our Board of Directors with industry executives with proven experience in oil and natural gas operations, finance and international operations; - Redefined our strategic priorities to focus on value creation; - Initiated capital conservation steps and financial transactions to de-leverage the company and improve cash flow for reinvestment; - Undertook a comprehensive study of our core Venezuelan asset to attempt to enhance the value of its production, thus ultimately increasing cash flow and potentially extending its productive life. 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. 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 advisors, are conducting a comprehensive review of strategic alternatives, including, but not limited to, selling all or part of our existing assets in Venezuela and Russia, debt restructuring, some combination thereof, 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. Our results of operations reflect the results of Geoilbent for the twelve months ended September 30, 2000, 1999 and 1998, and the results of Arctic Gas for the twelve months ended September 30, 2000 and 1999. 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 each of the years in the three year period ended December 31, 2000 and the financial condition as of December 31, 2000 and 1999 in conjunction with our Consolidated Financial Statements and related Notes thereto. 27 27 We have presented selected expense items from our consolidated income statement as a percentage of oil and natural gas sales in the following table:
YEARS ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ---- ---- ---- Operating Expenses................................... 34% 44% 49% Depletion, Depreciation and Amortization............. 12 19 40 General and Administrative........................... 12 29 26 Taxes Other Than on Income........................... 3 4 4 Interest............................................. 21 33 39
YEARS ENDED DECEMBER 31, 2000 AND 1999 Our results of operations for the year ended December 31, 2000 primarily reflected the results for Benton-Vinccler, C.A. in Venezuela, which accounted for substantially all of our production and oil sales revenue. As a result of increases in world crude oil prices, partially offset by lower production from the South Monagas Unit, oil sales in Venezuela were 57 percent higher in 2000 compared with 1999. Realized fees per barrel increased 62 percent (from $9.21 in 1999 to $14.94 in 2000) and oil sales quantities decreased 3 percent (from 9.7 MMBbls of oil in 1999 to 9.4 MMBbls of oil in 2000). Our operating expenses from the South Monagas Unit increased 21 percent primarily due to increased chemical treatment, electricity and natural gas compression station maintenance and operating costs, partially offset by reduced salaries and material costs. We had revenues of $140.3 million for the year ended December 31, 2000. The expenses we incurred during the period consisted of: - operating expenses of $47.4 million; - depletion, depreciation and amortization expense of $17.2 million; - write-downs of oil and gas properties and impairments of $1.3 million; - general and administrative expense of $16.7 million; - taxes other than on income of $4.4 million; - interest expense of $29.0 million; - income tax expense of $14.0 million; and - minority interest of $7.9 million. Other items of income consisted of: - investment income and other of $8.6 million; - net gain on exchange rates of $0.3 million; - equity in net earnings of affiliated companies of $5.3 million; and - extraordinary gain on the repurchase of long-term notes of $4.0 million. Our net income was $20.5 million or $0.66 per share (diluted). By comparison, we had revenues of $89.1 million for the year ended December 31, 1999. The expenses we incurred during the period consisted of: - operating expenses of $39.4 million; - depletion, depreciation and amortization expense of $16.5 million; - write-downs of oil and gas properties and impairments of $25.9 million; - general and administrative expense of $26.0 million; - taxes other than on income of $3.8 million; - interest expense of $29.2 million; - income tax benefit of $7.5 million; and - minority interest of $0.9 million. Other items of income consisted of: - investment income and other of $9.0 million; - net gain on exchange rates of $1.0 million; and - equity in net earnings of affiliated companies of $2.9 million. 28 28 Our net loss was $32.3 million or $1.09 per share (diluted). Our revenues increased $51.2 million, or 57 percent, during the year ended December 31, 2000 compared with 1999. This was due to increased oil sales revenue in Venezuela as a result of increases in world crude oil prices, partially offset by lower sales quantities. Our sales quantities for the year ended December 31, 2000 from Venezuela were 9.4 MMBbls compared to 9.7 MMBbls for the year ended December 31, 1999. The decrease in sales quantities of 302,890 Bbls, or 3 percent, was due primarily to production declines beginning in 1999 resulting from the curtailment of the Venezuelan development drilling program. Venezuelan production declined to 24,300 Bbls of oil per day by the end of 1999. Production increased to 28,000 Bbls or oil per day by the end of 2000 as a result of drilling 26 additional wells during the year. Prices for crude oil averaged $14.94 per Bbl (pursuant to terms of an operating service agreement) from Venezuela compared with $9.21 per Bbl for 1999. Our operating expenses increased $8.0 million, or 20 percent, during the year ended December 31, 2000 compared to the year ended December 31, 1999. This was primarily due to increased chemical treatment, electricity and natural gas compression station maintenance and operating costs, which were partially offset by reduced salaries and material costs at the South Monagas Unit in Venezuela. Depletion, depreciation and amortization increased $0.7 million, or 4 percent, during the year ended December 31, 2000 compared with 1999 primarily due to decreased proved reserves and increased future development costs at the South Monagas Unit. Depletion expense per barrel of oil produced from Venezuela during 2000 was $1.68 compared with $1.53 during 1999. We recognized write-downs of capitalized costs of $1.3 million associated with exploration activities in Jordan and California during the year ended December 31, 2000 compared with $25.9 million associated with exploration activities in California, China, Senegal and Jordan during the year ended December 31, 1999. General and administrative expenses decreased $9.3 million, or 36 percent, during the year ended December 31, 2000 compared with 1999. This was primarily due to the following: - our reduction in workforce and related restructuring costs in 1999; - the write-off of the joint interest receivable due from Molino Energy at December 31, 1999 associated with the California Leases; and - an allowance for doubtful accounts in 1999, related to amounts owed to us by our former Chief Executive Officer (see Note 14 of Notes to the Consolidated Financial Statements). Taxes other than on income increased $0.6 million, or 16 percent, during the year ended December 31, 2000 compared with 1999. This was primarily due to increased Venezuelan municipal taxes, which are a function of oil revenues. Investment income and other decreased $0.4 million, or 4 percent, during the year ended December 31, 2000 compared with 1999. This was due to lower average cash and marketable securities balances. Interest expense decreased $0.2 million, or 1 percent, during the year ended December 31, 2000 compared with 1999. This was primarily due to the reduction of debt balances, partially offset by a reduction of capitalized interest expense. Net gain on exchange rates decreased $0.7 million, or 70 percent for the year ended December 31, 2000 compared with 1999. This was due to changes in the value of the Bolivar. We realized income before income taxes and minority interest of $33.1 million during the year ended December 31, 2000 compared with a loss of $41.7 million in 1999. This resulted in increased income tax expense of $21.5 million. The effective tax rate of 42 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 increased $7.0 million for the year ended December 31, 2000 compared to 1999. This was primarily due to the increased profitability of Benton-Vinccler. Equity in net earnings of affiliated companies increased $2.4 million, or 83 percent, during the year ended December 31, 2000 compared with 1999. This was primarily due to the increased income from Geoilbent. Our share of revenues from Geoilbent was $25.2 million for the year ended September 30, 2000 compared with revenues of $11.1 million for 1999. The increase of $14.1 million, or 127 percent, was due to significantly higher world crude oil prices partially offset by lower sales quantities. Prices for Geoilbent's crude oil averaged $17.45 per Bbl during the year ended September 30, 2000 compared with $7.68 per Bbl for the year ended September 30, 1999. Our share of Geoilbent oil sales quantities decreased by 6,819 Bbls, or 0.5 percent, from 1,451,000 BBls sold during the year ended September 30, 1999 to 1,444,181 Bbls sold during the year ended September 30, 2000. The decrease in oil sales was due primarily to the temporary interruption of production in early 2000 resulting from an accident during the period that affected certain production facilities. We recorded extraordinary income of $4.0 million during the year ended December 31, 2000 related to the repurchase at a discount of $17 million of our senior unsecured notes due in 2003. We exchanged a total of 4.2 million shares of our common stock with a market value of $9.3 million and cash of $3.5 million for $17 million in notes. We also wrote-off $0.2 million in unamortized loan fees related to the notes. 29 29 CAPITAL RESOURCES AND LIQUIDITY The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see Risk Factors). 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. Working Capital. Our capital resources and liquidity are affected by the timing of our semiannual interest payments of approximately $11.4 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. The current interest rate on the facility is 16.5 percent. We borrowed 5 billion Bolivars (approximately $7.2 million) in October under this facility, which we repaid in November 2000. In December, we borrowed another 4 billion Bolivars (approximately $5.7 million) at an interest rate of 12.5 percent, which we repaid in January 2001. We believe that similar arrangements will be available to us in future quarters. 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 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 above alternatives, or some combination thereof, will be available or, if available, will be on terms acceptable to us. 30 30 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:
YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 1998 -------------- ---------- --------- Net cash provided by (used in) operating activities ................. $ 51,763 $ (1,392) $ 2,156 Net cash provided by (used in) investing activities ................. (28,772) 20,989 4,134 Net cash used in financing activities ............................... (29,006) (15,648) (823) -------- -------- ------- Net increase (decrease) in cash ..................................... $ (6,015) $ 3,949 $ 5,467 ======== ======== =======
At December 31, 2000, we had current assets of $63.6 million and current liabilities of $51.3 million, resulting in working capital of $12.3 million and a current ratio of 1.24:1. This compares with our working capital of $32.1 million and a current ratio of 2.17:1 at December 31, 1999. The decrease in working capital of $19.8 million was primarily due to capital expenditures at the South Monagas Unit in Venezuela and additional investments in and advances to Arctic Gas Company during the year ended December 31, 2000. Cash Flow from Operating Activities. During the year ended December 31, 2000 and 1999, net cash provided by (used in) operating activities was approximately $51.8 million and $(1.4) million, respectively. Cash flow from operating activities increased by $53.2 million during the year ended December 31, 2000 compared with 1999. This was primarily due to increased collections of accrued oil revenues, increased accounts payable and accrued expenses associated with the alliance agreements with Schlumberger and Helmerich & Payne and reduced general and administrative expenses, which were partially offset by increases in operating expenses, income taxes and taxes other than on income. Collections of accrued oil revenues increased $51.4 million, and accounts payable and accrued expenses increased $22.6 million during the year ended December 31, 2000 compared with 1999. Cash Flow from Investing Activities. During the year ended December 31, 2000 and 1999, we had drilling and production related capital expenditures of approximately $57.2 million and $37.0 million, respectively. Of the 2000 expenditures: - $53.9 million was attributable to the development of the South Monagas Unit in Venezuela; - $ 0.2 million was related to costs on the Delta Centro Block in Venezuela; - $ 1.0 million was related to the Sirhan Block in Jordan; - $ 1.1 million was attributable to the Gulf Coast; and - $ 1.0 million was attributable to other projects. In addition, during the year ended December 31, 2000, we increased our investment in Arctic Gas by $10.8 million. In August 1999, Benton-Vinccler sold its power generation facility located in the Uracoa Field of the South Monagas Unit in Venezuela for $15.1 million. Concurrent with the sale, Benton-Vinccler entered into a long-term power purchase agreement with the purchaser of the facility to provide for the electrical needs of the field throughout the remaining term of the operating service agreement. Benton-Vinccler used the proceeds from the sale to repay indebtedness that was collateralized by our time deposit. Permanent repayment of a portion of the loan allowed us to reduce the cash collateral for the loan thereby making such cash available for working capital needs. 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 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, we suspended the development drilling program in Venezuela for a period of approximately six months starting in January 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 known 123 MMBbls (98 MMBbls net to Benton) of proved reserves of oil in the fields. Our goal will be an accelerated development program with lower cost production, starting from the second half of 2001, rising to an expected level of up to between 31,000-33,000 Bbls of oil equivalent per day in less than two years. This is based on current internal operating and financial assumptions and also assumes that we do not enter into a transaction under which we sell a significant portion of our assets, as described in "Item 1. Business - Management, Operational and Financial Restrictions." In the first half of 2001, we will concentrate on improving the production from the existing 143 available wells in Venezuela. Production, currently (as of March 23, 2001) at 28,500 Bbls of oil per day in Venezuela, is expected to decline to between 25,000 and 26,000 Bbls of oil per day by mid-year, then increase when the new development plan starts in the third quarter. 31 31 We expect capital expenditures of approximately $44.2 million during the next 12 months, including $32.9 million at the South Monagas Unit and $7.7 million at Delta Centro relating to the unused portion of the standby letter of credit that was paid in January 2001 to terminate the contract. We also expect to increase our investment in Arctic Gas by $5.0 million during the same period. 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 $22 million under this agreement. We continue to evaluate funding alternatives for the loans to Arctic Gas. 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 under the alliance agreements with Schlumberger and Helmerich & Payne 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 partners on techniques to optimize the production from new wells and believe that we can achieve improvements in production performance from the Uracoa Field. 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 1st and November 1st 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 December 31, 2000, we were in compliance with all covenants of the indentures. CONCLUSION While we can give you no assurance, we currently believe that our capital resources and liquidity will be adequate to fund our planned capital expenditures, investments in and advances to affiliates, and semiannual interest payment obligations for the next 12 months. Our expectation is based upon 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 is a significant decrease in either price or production levels related to the South Monagas Unit. Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well as various economic conditions that have historically affected the oil and natural gas business. Prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond our control. 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. RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1999 AND 1998 We had revenues of $89.1 million for the year ended December 31, 1999. The expenses we incurred during the period consisted of: - operating expenses of $39.4 million; - depletion, depreciation and amortization expense of $16.5 million; - write-downs of oil and gas properties and impairments of $25.9 million; - general and administrative expense of $26.0 million; - taxes other than on income of $3.8 million; - interest expense of $29.2 million; - income tax benefit of $7.5 million; and - minority interest of $0.9 million. Other items of income consisted of: - investment income and other of $9.0 million; - net gain on exchange rates of $1.0 million; and - equity in net earnings of affiliated companies of $2.9 million. 32 32 Our net loss was $32.3 million or $1.09 per share (diluted). By comparison, we had revenues of $82.2 million for the year ended December 31, 1998. The expenses we incurred during the period consisted of: - operating expenses of $40.1 million; - depletion, depreciation and amortization expense of $33.2 million; - write-downs of oil and gas properties and impairments of $193.9 million; - general and administrative expense of $21.5 million; - taxes other than on income of $3.7 million; - interest expense of $32.0 million; - income tax benefit of $24.9 million; and - minority interest reduction of $22.9 million. Other items of income consisted of: - investment income and other of $14.0 million; - net gain on exchange rates of $1.8 million; and - equity in net losses of affiliated companies of $5.1 million. Our net loss was $183.6 million or $6.21 per share (diluted). Revenues increased $6.9 million, or 8 percent, during the year ended December 31, 1999 compared with 1998. This was due to increased oil sales revenue in Venezuela as a result of increases in world crude oil prices substantially offset by a 21 percent decrease in oil sales quantities. Sales quantities for the year ended December 31, 1999 from Venezuela were 9.7 MMBbls compared with 12.2 MMBbls for the year ended December 31, 1998. The decrease in sales quantities of 2.5 MMBbls was primarily due to the curtailment in 1998 and 1999 of the Venezuelan development drilling program. Prices for crude oil averaged $9.21 per Bbl (pursuant to terms of an operating service agreement) from Venezuela for the year ended December 31, 1999 compared with $6.75 per Bbl for the year ended December 31, 1998. Our operating expenses decreased $0.7 million, or 2 percent, during the year ended December 31, 1999 compared with 1998. This was primarily due to a stabilization of operating expenses in Venezuela. Depletion, depreciation and amortization decreased $16.7 million, or 50 percent, during the year ended December 31, 1999 compared with 1998. This was primarily due to write-downs of oil and natural gas properties in Venezuela in 1998. Depletion expense per barrel of oil produced from Venezuela during the year ended December 31, 1999 was $1.53 compared with $2.62 during1998. Additionally, we recognized write-downs of capitalized costs of $25.9 million in 1999 associated with exploration activities in California, China, Senegal and Jordan. General and administrative expenses increased $4.5 million, or 21 percent, during the year ended December 31, 1999 compared with 1998. This was primarily due to: - our reduction in workforce and related restructuring costs; - increasing consulting and legal fees; - the write-off of the joint interest receivable due from Molino Energy at December 31, 1999 associated with the California Leases; and - an allowance for doubtful accounts related to amounts owed to us by our former Chief Executive Officer (see Note 14 of Notes to the Consolidated Financial Statements). Investment income and other decreased $5.0 million, or 36 percent, during the year ended December 31, 1999 compared with 1998 due to lower average cash and marketable securities balances. Interest expense decreased $2.8 million, or 9 percent, during the year ended December 31, 1999 compared with 1998 primarily due to capitalized interest. Net gain on exchange rates decreased $0.8 million, or 44 percent for the year ended December 31, 1999 compared with 1998 due to changes in the value of the Bolivar. We realized a loss before income taxes and minority interest of $41.7 million during the year ended December 31, 1999 compared with a loss of $226.3 million in 1998, which resulted in a decrease in income tax benefit of $17.4 million or 70 percent primarily due to increased taxable income in Venezuela. The net income attributable to the minority interest increased $23.8 million, or 104 percent for 1999 compared with 1998. This was primarily due to the increased profitability of Benton-Vinccler's operations in Venezuela. Equity in net earnings of affiliated companies were $2.9 million for the year ended December 31, 1999 compared with equity in net losses of affiliated companies of $5.1 million in 1998. The increase of $8.0 million was primarily due to the increased income from Geoilbent. Our share of revenues from Geoilbent was $11.1 million for the year ended September 30, 1999 compared with revenues of $8.1 million for the year ended September 30, 1998. The increase of $3.0 million, or 37 percent, was due to significantly higher sales quantities, which 33 33 were partially offset by lower average oil prices. Prices for Geoilbent's crude oil averaged $7.68 per Bbl during the year ended September 30, 1999 compared with $8.72 per Bbl for the year ended September 30, 1998. Our share of Geoilbent oil sales quantities increased by 527,398 Bbls, or 57 percent, from 923,602 Bbls sold during the year ended September 30, 1998 to 1,451,000 Bbls sold during the year ended September 30, 1999. The increase in oil sales was primarily due to the development of the North Gubkinskoye Field in Western Siberia region of Russia. RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1998 AND 1997 We had revenues of $82.2 million for the year ended December 31, 1998. Expenses incurred during the period consisted of: - operating expenses of $40.1 million; - depletion, depreciation and amortization expense of $33.2 million; - write-downs of oil and gas properties and impairments of $193.9 million; - general and administrative expense of $21.5 million; - taxes other than on income of $3.7 million; - interest expense of $32.0 million; - income tax benefit of $24.9 million; and - minority interest reduction of $22.9 million. Other items of income consisted of: - investment income and other of $14.0 million; - net gain on exchange rates of $1.8 million; and - equity in net losses of affiliated companies of $5.1 million. Our net loss was $183.6 million or $6.21 per share (diluted). By comparison, we had revenues of $154.0 million for the year ended December 31, 1997. Expenses incurred during the period consisted of: - operating expenses of $35.2 million; - depletion, depreciation and amortization expense of $44.5 million; - general and administrative expense of $17.7 million; - taxes other than on income of $5.4 million; - interest expense of $24.1 million; - income tax expense of $16.6 million; and - minority interest of $6.3 million. Other items of income consisted of: - investment income and other of $12.6 million; - net gain on exchange rates of $2.0 million; and - equity in net losses of affiliated companies of $0.8 million. Our net income was $18.0 million or $0.59 per share (diluted). Our revenues decreased $71.8 million, or 47 percent, during the year ended December 31, 1998 compared with 1997. This was due to reduced oil sales revenue in Venezuela as a result of declines in world crude oil prices and a 21 percent decrease in oil sales quantities largely due to operational problems with certain high volume wells. Sales quantities for the year ended December 31, 1998 from Venezuela were 12.2 MMBbls compared with 15.4 MMBbls for the year ended December 31, 1997. Prices for crude oil averaged $6.75 per Bbl (pursuant to terms of an operating service agreement) from Venezuela for the year ended December 31, 1998 compared with $10.01 per Bbl for the year ended December 31, 1997. Our operating expenses increased $4.9 million, or 14 percent, during the year ended December 31, 1998 compared with 1997. This was primarily due to continuing maturation of the Uracoa oil field in Venezuela resulting in higher water handling, natural gas handling, workover, transportation and chemical costs. The increase was partially offset by reduced oil production in Venezuela. Depletion, depreciation and amortization decreased $11.3 million, or 25 percent, during the year ended December 31, 1998 compared with 1997. This was primarily due to write-downs of oil and natural gas properties and reduced oil sales in Venezuela in 1998, partially offset by increased capital requirements in Venezuela. Depletion expense per barrel of oil produced from Venezuela during the year ended 34 34 December 31, 1998 was $2.62 compared with $2.83 during the previous year. Additionally, we recognized write-downs of oil and gas properties during 1998 in the Venezuelan cost center of $187.8 million pursuant to the ceiling limitation prescribed by the full cost method of accounting. The write-downs were a result of the effect of declines in world crude oil prices on the prices realized by us for our Venezuelan oil sales. We also recognized $6.1 million of impairment expense associated with certain exploration activities. General and administrative expenses increased $3.8 million, or 21 percent, during the year ended December 31, 1998 compared with 1997. This was primarily due to an allowance for doubtful accounts related to amounts owed to us by our former Chief Executive Officer (see Note 14 of the Notes to Consolidated Financial Statements) and costs incurred in our China operation. Taxes other than on income decreased $1.7 million, or 31 percent, during the year ended December 31, 1998 compared to 1997. This was primarily due to decreased Venezuelan municipal taxes, which are a function of oil revenues. Investment income and other increased $1.4 million, or 11 percent, during the year ended December 31, 1998 compared with 1997. This increase was due to higher average cash and marketable securities balances. Interest expense increased $7.9 million, or 33 percent, during the year ended December 31, 1998 compared with 1997. This increase was primarily due to the issuance of $115 million in senior unsecured notes in November 1997. Net gain on exchange rates decreased $0.2 million, or 10 percent for the year ended December 31, 1998 compared with 1997 due to changes in the value of the Bolivar. We realized a loss before income taxes and minority interest of $226.3 million during the year ended December 31, 1998 compared with income of $42.1 million in 1997. This resulted in a decrease in income tax expense of $41.5 million or 250 percent primarily due to decreased taxable income in Venezuela as a result of the write-downs of oil and gas properties. The net income attributable to the minority interest decreased $29.2 million, or 463 percent for 1998 compared with 1997 as a result of the decreased profitability of Benton-Vinccler's operations in Venezuela. Equity in net losses of affiliated companies were $5.1 million for the year ended December 31, 1998 compared with equity in net losses of affiliated companies of $0.8 million in 1997. The increase of $4.3 million was due to reduced income from Geoilbent. Our share of revenues from Geoilbent were $8.1 million for the year ended September 30, 1998 compared with revenues of $9.9 million for the year ended September 30, 1997. The decrease of $1.8 million, or 18 percent, was due to lower average oil prices partially offset by higher sales quantities. Prices for Geoilbent's crude oil averaged $8.72 per Bbl during the year ended September 30, 1998 compared with $11.72 per Bbl for the year ended September 30, 1997. Our share of Geoilbent oil sales quantities increased by 43,454 Bbls, or 5 percent, from 880,148 Bbls sold during the year ended September 30, 1997 to 923,602 Bbls sold during the year ended September 30, 1998. The increase in oil sales was primarily due to the development of the North Gubkinskoye Field in Western Siberia region of Russia. 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 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 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 Bbls 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 cash and a 5 percent carried working interest in up to four wells that may be drilled in the future. 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. 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 35 35 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. A 3-D seismic survey has been conducted over the southwestern portion of, and a 371 kilometer 2-D seismic survey has been acquired for, the Delta Centro Block in Venezuela. During 1999, the Block's first exploration well, the Jarina 1-X, penetrated a thick potential reservoir sequence, but encountered no commercial hydrocarbons. Our total cost of acquiring seismic data and drilling the Jarina 1-X was $15.4 million as December 31, 2000. In January 2001, we and our bidding partners reached an agreement with Corporacion Venezolana del Petroleo, S.A. to terminate the contract and our exploration obligation in exchange for the unused portion of the standby letter of credit of $7.7 million. 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 December 31, 2000, we had recorded no proved reserves attributable to this petroleum contract. In August 1997, we acquired the rights to an Exploration and Production Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to explore, develop and produce the Sirhan Block in southeastern Jordan. Under the terms of the PSA, we were obligated to make certain capital and operating expenditures in up to three phases over eight years. We were obligated to spend $5.1 million in the first exploration phase, which was extended to May 2000, for which we posted a $1 million standby letter of credit, collateralized in full by a time deposit. During the first quarter of 1998, we reentered two wells and tested two different reservoirs. The WS-9 well tested significant, but non-commercial amounts of natural gas; the WS-10 well resulted in no commercial amounts of hydrocarbons. Therefore, at December 31, 1998, we wrote down $3.7 million in capitalized costs incurred to date related to the PSA. During 1999, we incurred an additional $0.3 million in capitalized costs, which were written off at December 31, 1999. As of the May 17, 2000 expiration date of the PSA, we had elected not to complete the first exploration phase of the agreement. As a result, during the second quarter of 2000, we recorded a liability to the NRA for the obligation remaining under the PSA resulting in impairment expense of $1.0 million. The NRA collected on the letter of credit in August 2000. In April 1998, we signed an agreement to earn a 40 percent equity interest in Arctic Gas Company, formerly Severneftegaz. 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 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 significant influence it exercises 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 December 31, 2000, we had loaned $22.0 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 9 percent equity interest. From December 1998 through November 2000, we purchased shares representing an additional 20 percent equity interest not subject to any 36 36 sale or transfer restrictions. We owned a total of 60 percent of the outstanding voting shares of Arctic Gas as of December 31, 2000, of which approximately 29 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 Field 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 field during the third quarter of 1992 with the construction of a 37-mile oil pipeline and installation of temporary production facilities. 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 increased to 34 Euros per ton (approximately $3.80 per barrel) on November 3, 2000 from 15 Euros per ton in 1999. 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 year ended December 31, 2000, our net foreign exchange gains attributable to our Venezuelan and Russian operations were $0.3 million. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, many of which are beyond our control. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan and Russian currencies to the U.S. dollar. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls. Our operations are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by price controls, tax and other laws relating to the petroleum industry, by changes in such laws and by changing administrative regulations and the interpretations and application of such rules and regulations. In addition, various federal, state, local and international laws and regulations covering the discharge of materials into the environment, the disposal of oil and natural gas wastes, or otherwise relating to the protection of the environment, may affect our operations and results. COST REDUCTIONS In an effort to reduce general and administrative expenses, we reduced our administrative and technical staff in Carpinteria by 10 people in October 1999. In connection with the reduction in workforce, we recorded termination benefits expenses in October 1999 of $0.8 million. All amounts were paid as of December 31, 2000. RISK FACTORS In addition to the other information set forth elsewhere in this Form 10-K, the following factors should be carefully considered when evaluating the Company. 37 37 OIL PRICE DECLINES AND VOLATILITY COULD ADVERSELY AFFECT OUR REVENUE, CASH FLOWS AND PROFITABILITY. Prices for oil fluctuate widely. The average price we received for oil in Venezuela increased from approximately $9.21 per Bbl for the year ended December 31, 1999, to $14.94 per Bbl for the year ended December 31, 2000. During the same period, the average price we received for oil in Russia increased from $7.68 per Bbl to $17.45 per Bbl. Our Venezuelan 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, which dampens both any upward and downward effects of changing prices on our Venezuelan oil sales and cash flows. Our revenues, profitability and future rate of growth depend 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. In addition, we may have ceiling test writedowns when prices decline. Lower prices may also reduce the amount of oil that we can produce economically. We cannot predict future oil prices. Factors that can cause this fluctuation include: - relatively minor changes in the supply of and demand for oil; - market uncertainty; - the level of consumer product demand; - weather conditions; - domestic and foreign governmental regulations; - the price and availability of alternative fuels; - political and economic conditions in oil producing countries, particularly those in the Middle East; and - overall economic conditions. WE MAY NOT HAVE AVAILABLE FUNDING TO EXECUTE OUR DRILLING PROGRAMS. We have historically addressed our long-term liquidity needs through the issuance of debt and equity securities and the use of cash provided by operating activities. We continue to examine the following alternative sources of long-term capital: - sales of properties; - joint venture financing; - the issuance of non-recourse production-based financing; - the sale of common stock, preferred stock or other equity securities; - bank borrowings or the issuance of debt securities; - sales of prospects and technical information. The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil prices and our value and performance. We may be unable to execute our planned drilling program if we cannot obtain capital from these sources. ESTIMATES OF OIL AND NATURAL GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptions required by the Securities and Exchange Commission relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. Such process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used. Such variances may be material. At December 31, 2000, approximately 57 percent of our estimated proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The estimates of our future reserves include the assumption that we will make significant capital expenditures to develop these reserves. Although we have prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. See Supplemental Information on Oil and Natural Gas Producing Activities. You should not assume that the present value of future net revenues referred to is the current market value of our estimated oil and natural gas reserves. In accordance with Securities and Exchange Commission requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption or in governmental 38 38 regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount factor, which is required by the Securities and Exchange Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and our risks or the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor. LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS. As of December 31, 2000, our long-term debt was $213 million. Our long-term debt represented 94 percent of our total capitalization at December 31, 2000. Our level of debt affects our operations in several important ways, including the following: - a significant portion of our cash flow from operations is used to pay interest on borrowings; - the covenants contained in the indentures governing our debt limit our ability to borrow additional funds or to dispose of assets; - the covenants contained in the indentures governing our debt affect our flexibility in planning for, and reacting to, changes in business conditions; - the high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and - the terms of the indentures governing our debt permit our creditors to accelerate payments upon an event of default or a change of control. The intrinsic value of our assets is burdened by a heavy debt load and constraints on capital to optimize our producing properties in Venezuela and develop our unexploited acreage in Russia. A high level of debt increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance and crude oil and natural gas realizations. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. If we are unable to repay our debt at maturity out of cash on hand, we could attempt to refinance such debt, or repay such debt with the proceeds of any equity offering, or sell all or part of our assets in Venezuela and Russia, or some combination thereof. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions and our value and performance at the time of such offering or other financing. We cannot assure you that any such offering or refinancing can be successfully completed. LOWER OIL AND NATURAL GAS PRICES MAY CAUSE US TO RECORD CEILING LIMITATION WRITEDOWNS. We use the full cost method of accounting to report our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce stockholders' equity. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. In 1998, we recorded after-tax write-downs of $158.5 million ($187.8 million pre-tax). In 1999 and 2000, we recorded no ceiling limitation write-downs. We cannot assure you that we will not experience ceiling limitation write-downs in the future. WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES. In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful exploration and development activities. Our future oil production is highly dependent upon our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND NATURAL GAS DRILLING AND PRODUCTION ACTIVITIES. Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often 39 39 uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include: - unexpected drilling conditions; - pressure or irregularities in formations; - equipment failures or accidents; - weather conditions; and - shortages in experienced labor or shortages or delays in the delivery of equipment. The prevailing price of oil also affects the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs. THE OIL AND NATURAL GAS INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS. The oil and natural gas industry experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pump and pipe failures, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, natural gas leaks, pipeline ruptures or discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. OUR CONCENTRATION OF ASSETS INCREASES OUR EXPOSURE TO PRODUCTION DECLINES. During 2000, the production from the South Monagas Unit in Venezuela represented approximately 100 percent of our total production from consolidated companies. Our production, revenue and cash flow will be adversely affected if production from the South Monagas Unit decreases significantly. OUR INTERNATIONAL OPERATIONS MAY BE ADVERSELY AFFECTED BY CURRENCY FLUCTUATIONS AND ECONOMIC AND POLITICAL DEVELOPMENTS. We have substantially all of our operations in Venezuela and Russia. The expenses of such operations are payable in local currency while most of the revenue from oil sales is paid in U.S. dollars. As a result, our operations are subject to the risk of fluctuations in the relative value of the Bolivar, Ruble and U.S. dollar. Our foreign operations may also be adversely affected by political and economic developments, royalty and tax increases and other laws or policies in these countries, as well as U.S. policies affecting trade, taxation and investment in other countries. COMPETITION WITHIN THE INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS. We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies for the acquisition of desirable oil and gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours. OUR OIL AND NATURAL GAS OPERATIONS ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS. Our oil and natural gas operations are subject to various foreign governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity. In addition, our operations are subject to taxation policies, that in Russia have changed significantly. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. FOREIGN OPERATIONS RISK. Our operations in areas outside the U.S. are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, war, insurrection and other political risks, increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over the Company's international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade and taxation. To date, our international operations have not been materially affected by these risks. 40 40 ITEM 7A. 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 Bbl in 1997 to $6.75 per Bbl in 1998 and increased to $14.94 per Bbl in 2000. Based on our budgeted production and costs, we will require an average realization in Venezuela of approximately $12.50 per Bbl 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 1999 or 2000. INTEREST RATES Total long-term debt at December 31, 2000, consisted of $213 million of fixed-rate senior unsecured notes maturing in 2003 ($108 million) and 2007 ($105 million). A hypothetical 10 percent adverse change in the floating rate would not have had a material affect on our results of operations for the year ended December 31, 2000. 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. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA The information required by this item is included herein on pages S-1 through S-33. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE No information is required to be reported under this item. 41 41 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT * ITEM 11. EXECUTIVE COMPENSATION * ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT * ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS * * Reference is made to information under the captions "Election of Directors", "Executive Officers", "Executive Compensation", "Security Ownership of Certain Beneficial Owners and Management", and "Certain Relationships and Related Transactions" in our Proxy Statement for the 2001 Annual Meeting of Stockholders. If our Proxy Statement is not disseminated prior to April 30, 2001, we will file an amendment of Part III of Form 10-K on or before that date. 42 42 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Index to Financial Statements: Page ---- Reports of Independent Accountants ................................S-1 Consolidated Balance Sheets at December 31, 2000 and 1999 .........S-2 Consolidated Statements of Operations for the Years Ended December 31, 2000, 1999 and 1998...................................S-3 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2000, 1999 and 1998.......................S-4 Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998...................................S-5 Notes to Consolidated Financial Statements.........................S-7 2. Consolidated Financial Statement Schedules: Schedule II - Valuation and Qualifying Accounts 3. Exhibits: 3.1 Certificate of Incorporation filed September 9, 1988 (Incorporated by reference to Exhibit 3.1 to our Registration Statement (Registration No. 33-26333). 3.2 Amendment to Certificate of Incorporation filed June 7, 1991 (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-39214)). 3.3 Restated Bylaws. 4.1 Form of Common Stock Certificate (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)). 10.4 Form of Employment Agreements (Exhibit 10.19) (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)). 10.7 Benton Oil and Gas Company 1991-1992 Stock Option Plan (Exhibit 10.14) (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-43662)). 10.8 Benton Oil and Gas Company Directors' Stock Option Plan (Exhibit 10.15) (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-43662)). 10.9 Agreement dated October 16, 1991 among Benton Oil and Gas Company, Puror State Geological Enterprises for Survey, Exploration, Production and Refining of Oil and Gas; and Puror Oil and Gas Production Association (Exhibit 10.14) (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-46077)). 43 43 10.10 Operating Service Agreement between Benton Oil and Gas Comany and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission--Exhibit 10.25) (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-52436)). 10.16 Indenture dated May 2, 1996 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to $125,000,000, 11 5/8 percent Senior Notes Due 2003 (Incorporated by reference to Exhibit 4.1 to our S-4 Registration Statement filed June 17, 1996, SEC Registration No. 333-06125). 10.17 Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to an aggregate of $115,000,000 principal amount of 9 3/8 percent Senior Notes due 2007 (Incorporated by reference to Exhibit 10.1 to our Form 10-Q for the quarter ended September 30, 1997). 10.18 Separation Agreement dated January 4, 2000 between Benton Oil and Gas Company and Mr. A.E. Benton. (Incorporated by reference to Exhibit 10.18 to our Form 10-K for the year ended December 31, 1999). 10.19 Consulting Agreement dated January 4, 2000 between Benton Oil and Gas Company and Mr. A.E. Benton. (Incorporated by reference to Exhibit 10.19 to our Form 10-K for the year ended December 31, 1999). 10.20 Employment Agreement dated July 10, 2000 between Benton Oil and Gas Company and Peter J. Hill. (Incorporated by reference to Exhibit 10.20 to our Form 8-K, filed June 6, 2000). 10.21 Benton Oil and Gas Company 1999 Employee Stock Option Plan. 10.22 Benton Oil and Gas Company Non-Employee Director Stock Purchase Plan. 10.23 Employment Agreement dated December 7, 2000 between Benton Oil and Gas Company and Steven W. Tholen. 21.1 List of subsidiaries. 23.1 Consent of PricewaterhouseCoopers LLP. 23.2 Consent of Huddleston & Co., Inc. 23.3 Consent of Ryder Scott Company, L.P. 27.1 Financial Data Schedule. - ----------------- (b) Reports on Form 8-K On October 21, 2000, we filed a report on Form 8-K, under Item 5, "Other Events" regarding the expansion of the board of directors to eight members and the election of five new members. 44 44 REPORT OF INDEPENDENT ACCOUNTANTS --------------------------------- To the Board of Directors and Stockholders of Benton Oil and Gas Company In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholders' equity (deficit) and cash flows present fairly, in all material respects, the financial position of Benton Oil and Gas Company and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the related financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 1 to the financial statements, in 1999 the Company changed its method of reporting its investment in Geoilbent. PricewaterhouseCoopers LLP Los Angeles, California March 23, 2001 S-1 45 45
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES Consolidated Balance Sheets (in thousands) DECEMBER 31, 2000 1999 ---- ---- ASSETS ------ Current Assets: Cash and cash equivalents ..................................................... $ 15,132 $ 21,147 Restricted cash ............................................................... 12 12 Marketable securities ......................................................... 1,303 4,469 Accounts and notes receivable: Accrued oil and natural gas sales .......................................... 38,003 27,339 Joint interest and other, net .............................................. 6,778 4,993 Prepaid expenses and other .................................................... 2,404 1,635 --------- --------- Total Current Assets .................................................... 63,632 59,595 Restricted Cash .................................................................. 10,920 46,449 Other Assets ..................................................................... 5,891 10,569 Deferred Income Taxes ............................................................ 4,293 12,186 Investments In and Advances To Affiliated Companies .............................. 77,741 61,357 Property and Equipment: Oil and gas properties (full cost method-costs of $16,634 and $16,117 excluded from amortization in 2000 and 1999, respectively) ................. 490,548 435,449 Furniture and fixtures ........................................................ 11,049 10,031 --------- --------- 501,597 445,480 Accumulated depletion, impairment and depreciation ............................ (377,627) (359,325) --------- --------- Total Property and Equipment ............................................ 123,970 86,155 --------- --------- $ 286,447 $ 276,311 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) --------------------------------------------- Current Liabilities: Accounts payable, trade and other ............................................. $ 12,804 $ 3,317 Accrued expenses .............................................................. 25,102 17,105 Accrued interest payable ...................................................... 3,733 4,686 Income taxes payable .......................................................... 3,909 2,392 Short-term borrowings ......................................................... 5,714 - Current portion of long-term debt ............................................. - 2 --------- --------- Total Current Liabilities ............................................... 51,262 27,502 Long-Term Debt ................................................................... 213,000 264,575 Commitments and Contingencies .................................................... - - Minority Interest ................................................................ 9,281 1,412 Stockholders' Equity (Deficit): 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 at December 31, 2000 and 1999; issued 33,872 and 29,627 shares at December 31, 2000 and 1999 .............................................. 339 296 Additional paid-in capital .................................................... 156,629 147,078 Retained deficit .............................................................. (143,365) (163,853) Treasury stock, at cost, 50 shares ............................................ (699) (699) --------- --------- Total Stockholders' Equity (Deficit) .................................... 12,904 (17,178) --------- --------- $ 286,447 $ 276,311 ========= =========
See accompanying notes to consolidated financial statements S-2 46 46
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES Consolidated Statements of Operations (in thousands, except per share data) YEARS ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ---- ---- ---- REVENUES Oil and natural gas sales ............................................ $ 140,284 $ 89,060 $ 82,212 ---------- ---------- ---------- 140,284 89,060 82,212 ---------- ---------- ---------- EXPENSES Operating expenses ................................................... 47,430 39,393 40,066 Depletion, depreciation and amortization ............................. 17,175 16,519 33,157 Write-down of oil and gas properties and impairments ................. 1,346 25,891 193,893 General and administrative ........................................... 16,739 25,969 21,485 Taxes other than on income ........................................... 4,390 3,813 3,677 ---------- ---------- ---------- 87,080 111,585 292,278 ---------- ---------- ---------- Income (Loss) from Operations ........................................... 53,204 (22,525) (210,066) Other Non-Operating Income (Expense) Investment earnings and other ........................................ 8,559 8,986 13,982 Interest expense ..................................................... (28,973) (29,247) (32,007) Net gain on exchange rates ........................................... 326 1,044 1,767 ---------- ---------- ---------- (20,088) (19,217) (16,258) ---------- ---------- ---------- Income (Loss) from Consolidated Companies Before Income Taxes and Minority Interests ......................................... 33,116 (41,742) (226,324) Income Tax Expense (Benefit) ............................................ 14,032 (7,526) (24,911) ---------- ---------- ---------- Income (Loss) Before Minority Interests ................................. 19,084 (34,216) (201,413) Minority Interests in Consolidated Subsidiary Companies ................. 7,869 937 (22,895) ---------- ---------- ---------- Income (Loss) from Consolidated Companies ............................... 11,215 (35,153) (178,518) Equity in Net Earnings (Losses) of Affiliated Companies ................. 5,313 2,869 (5,062) ---------- ---------- ---------- Income (Loss) Before Extraordinary Income ............................... 16,528 (32,284) (183,580) Extraordinary Income on Debt Repurchase, Net of Tax of $0 ............... 3,960 - - ---------- ---------- ---------- Net Income (Loss) ....................................................... $ 20,488 $ (32,284) $ (183,580) ========== ========== ========== Net Income (Loss) Per Common Share: Basic: Income (Loss) before extraordinary income ........................... $ 0.54 $ (1.09) $ (6.21) Extraordinary Income ................................................ 0.13 - - ---------- ---------- ---------- Net Income (Loss) ................................................... $ 0.67 $ (1.09) $ (6.21) ========== ========== ========== Diluted: Income (Loss) Before Extraordinary Income ........................... $ 0.53 $ (1.09) $ (6.21) Extraordinary Income ................................................ 0.13 - - ---------- ---------- ---------- Net Income (Loss) ................................................... $ 0.66 $ (1.09) $ (6.21) ========== ========== ==========
See accompanying notes to consolidated financial statements. S-3 47 47
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES Consolidated Statements of Stockholders' Equity (Deficit) (in thousands) EMPLOYEE COMMON ADDITIONAL RETAINED NOTE SHARES COMMON PAID-IN EARNINGS TREASURY RECEIVABLE, ISSUED STOCK CAPITAL (DEFICIT) STOCK NET TOTAL ------- ----- -------- --------- ----- ------- --------- BALANCE AT JANUARY 1, 1998 ................ 29,522 $ 295 $146,125 $ 52,011 $(699) $ - $ 197,732 Issuance of common shares: Exercise of stock options ............. 105 1 794 - - - 795 Extension of warrants ................. - - 135 - - - 135 Employee note receivable, net ............. - - - - - (2,093) (2,093) Net loss .................................. - - - (183,580) - - (183,580) ------- ----- -------- --------- ----- ------- --------- BALANCE AT DECEMBER 31, 1998 .............. 29,627 296 147,054 (131,569) (699) (2,093) 12,989 Issuance of common shares: Extension of warrants ................. - - 24 - - - 24 Employee note receivable, net ............. - - - - - 2,093 2,093 Net loss .................................. - - - (32,284) - - (32,284) ------- ----- -------- --------- ----- ------- --------- BALANCE AT DECEMBER 31, 1999 .............. 29,627 296 147,078 (163,853) (699) - (17,178) Issuance of common shares: Exercise of stock options ............. 85 1 316 - - - 317 Extension of warrants ................. - - 12 - - - 12 Repurchase of debt .................... 4,160 42 9,223 - - - 9,265 Net income ................................ - - - 20,488 - - 20,488 ------- ----- -------- --------- ----- ------- --------- BALANCE AT DECEMBER 31, 2000 .............. 33,872 $ 339 $156,629 $(143,365) $(699) $ - $ 12,904 ======= ===== ======== ========= ===== ======= =========
See accompanying notes to consolidated financial statements S-4 48 48
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows (in thousands) YEARS ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ---- ---- ---- Cash Flows From Operating Activities: Net income (loss) .......................................................... $ 20,488 $ (32,284) $(183,580) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation and amortization ................................ 17,175 16,519 33,157 Write-down and impairment of oil and gas properties ..................... 1,346 25,891 193,893 Amortization of financing costs ......................................... 1,375 1,396 1,442 Loss on disposition of assets ........................................... 60 44 74 Equity in (earnings) losses of affiliated companies ..................... (5,313) (2,869) 5,062 Allowance and write off of employee notes and accounts receivable ....... 331 6,231 2,900 Minority interest in undistributed earnings (losses) of subsidiaries .... 7,869 937 (22,893) Extraordinary income from repurchase of debt ............................ (3,960) - - Deferred income taxes ................................................... 7,893 (9,210) (27,787) Changes in operating assets and liabilities: Accounts and notes receivable ........................................... (12,780) (6,414) 18,436 Prepaid expenses and other .............................................. (769) 1,750 (1,771) Accounts payable ........................................................ 9,487 (3,142) (16,410) Accrued interest payable ................................................ (953) (711) (131) Accrued expenses ........................................................ 7,997 (166) 2,468 Income taxes payable .................................................... 1,517 636 (2,704) --------- --------- --------- Net Cash Provided by (Used In) Operating Activities ..................... 51,763 (1,392) 2,156 --------- --------- --------- Cash Flows from Investing Activities: Proceeds from sale of property and equipment ............................... 800 15,100 - Additions of property and equipment ........................................ (57,196) (36,984) (101,917) Investment in and advances to affiliated companies ......................... (11,071) (13,052) (17,866) Increase in restricted cash ................................................ (271) (214) (230) Decrease in restricted cash ................................................ 35,800 19,435 8,884 Purchases of marketable securities ......................................... (12,638) (29,173) (55,438) Maturities of marketable securities ........................................ 15,804 65,877 170,701 --------- --------- --------- Net Cash Provided by (Used In) Investing Activities ..................... (28,772) 20,989 4,134 --------- --------- --------- Cash Flows from Financing Activities: Net proceeds from exercise of stock options and warrants ................... 330 24 930 Proceeds from issuance of short term borrowings and notes payable .......... 15,087 - - Payments on short term borrowings and notes payable ........................ (47,488) (15,439) (12) (Increase) decrease in other assets ........................................ 3,065 (233) (1,741) --------- --------- --------- Net Cash Used In Financing Activities ................................... (29,006) (15,648) (823) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents .................... (6,015) 3,949 5,467 Cash and Cash Equivalents at Beginning of Year ................................ 21,147 17,198 11,731 --------- --------- --------- Cash and Cash Equivalents at End of Year ...................................... $ 15,132 $ 21,147 $ 17,198 ========= ========= ========= Supplemental Disclosures of Cash Flow Information: Cash paid during the year for interest expense ............................. $ 28,326 $ 30,346 $ 30,389 ========= ========= ========= Cash paid during the year for income taxes ................................. $ 2,950 $ 2,600 $ 2,971 ========= ========= =========
See accompanying notes to consolidated financial statements. S-5 49 49 SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: During the year ended December 31, 2000, we repurchased $12.0 million face value of our senior unsecured notes with the issuance of 4.2 million shares of common stock (see Note 3). During the year ended December 31, 1999, we recorded an allowance for doubtful accounts related to amounts owed to us by our former Chief Executive Officer, including the portion of the note secured by our stock and stock options of $2.1 million (see Note 14). During the year ended December 31, 1998, we reduced stockholders' equity by $2.1 million, the portion of the note receivable from our former Chief Executive Officer secured by our stock and stock options (see Note 14). See accompanying notes to consolidated financial statements. S-6 50 50 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES Notes to Consolidated Financial Statements Years Ended December 31, 2000, 1999 and 1998 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 in which we have significant influence. All intercompany profits, transactions and balances have been eliminated. We account for our investment in Geoilbent, Ltd. ("Geoilbent") and Arctic Gas Company ("Arctic Gas"), formerly Severneftegaz, based on a fiscal year ending September 30 (see Note 2). In January 2000, in connection with the release of Emerging Issues Task Force (EITF) Issues Summary 00-01, "Applicability of the Pro Rata Method of Consolidation to Investments in Certain Partnerships and Other Unincorporated Joint Ventures", we reviewed the accounting for our investment in Geoilbent under the proportionate consolidation method. As a result of this review, we decided to report our investment in Geoilbent using the equity method effective December 31, 1999. This change had no effect on net income or our proportionate share of oil and natural gas reserves. It did, however, result in the reduction of our reported consolidated net cash flows for the years ended December 31, 1999 and 1998 of $5.3 million and $0.7 million, respectively. For the years ended December 31, 1999 and 1998, revenues were reduced by our proportionate share, which was $11.1 million and $8.1 million, respectively, operating expenses were reduced $9.1 million and $18.2 million, respectively and net other non-operating expenses and income taxes were reduced $3.4 million and $7.2 million, respectively. Summarized financial information for Geoilbent is included in Note 9. REVENUE RECOGNITION Oil and natural gas revenue is recognized when title passes to the customer. CASH AND CASH EQUIVALENTS Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months. RESTRICTED CASH Restricted cash represents cash and cash equivalents used as collateral for financing and letter of credit and loan agreements and is classified as current or non-current based on the terms of the agreements. MARKETABLE SECURITIES Marketable securities are carried at amortized cost. The marketable securities that 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 and $4.5 million in commercial paper at December 31, 2000 and 1999, respectively. ACCOUNTS AND NOTES RECEIVABLE Allowance for doubtful accounts related to employee notes at December 31, 2000 and 1999 was $6.2 million and $5.9 million, respectively (see Note 14). Allowance for doubtful accounts related to joint interest and other accounts receivable was $0.3 million at December 31, 2000 and 1999. OTHER ASSETS Other assets consist principally of costs associated with the issuance of long-term debt. Debt issuance costs are amortized on a straight-line basis over the life of the debt, which approximates the effective interest method of amortizing these costs. S-7 51 51 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. All costs associated with the acquisition, exploration, and development of oil and natural gas reserves are capitalized as incurred, including exploration overhead of $1.5 million, $2.1 million and $2.4 million for the years ended December 31, 2000, 1999 and 1998, respectively, and capitalized interest of $0.6 million and $2.1 million for the years ended December 31, 2000 and 1999, 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. 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. During 2000, 1999 and 1998, the Company recognized $1.3 million, $25.9 million and $6.1 million, respectively, of impairment expense associated with certain exploration activities. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty. Excluded costs at December 31, 2000 consisted of the following by year incurred (in thousands):
TOTAL 2000 1999 1998 PRIOR TO 1998 ------- ------- ------- ------- ------------- Property acquisition costs ................ $15,106 $ - $ - $ - $15,106 Exploration costs ......................... 1,528 518 46 90 874 ------- ------- ------- ------- ------- $16,634 $ 518 $ 46 $ 90 $15,980 ======= ======= ======= ======= =======
Substantially all of the excluded costs at December 31, 2000 relate to the acquisition of Benton Offshore China Company and exploration related to its Wan `An Bei property. The remaining excluded costs of $0.4 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 years ended December 31, 2000, 1999 and 1998 was $15.3 million, $14.8 million and $31.8 million ($1.68, $1.53 and $2.62 per equivalent barrel), respectively. A gain or loss is recognized on the sale of oil and gas properties only when the sale involves a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved property. 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 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $1.8 million, $1.6 million and $1.3 million for the years ended December 31, 2000, 1999 and 1998, respectively. The major components of property and equipment at December 31 are as follows (in thousands):
2000 1999 ---- ---- Proved property costs ................................................ $ 458,571 $ 409,526 Costs excluded from amortization ..................................... 16,634 16,117 Oilfield inventories ................................................. 15,343 9,806 Furniture and fixtures ............................................... 11,049 10,031 --------- --------- 501,597 445,480 Accumulated depletion, impairment and depreciation ................... (377,627) (359,325) --------- --------- $ 123,970 $ 86,155 ========= =========
We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the Securities and Exchange Commission. During 1998, due to declines in world crude oil prices, the ceiling tests resulted in write-downs of oil and gas properties in the Venezuela cost center of $187.8 million. S-8 52 52 TAXES ON INCOME Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. FOREIGN CURRENCY We have significant operations outside of the United States, principally in Venezuela and Russia. Both Venezuela and Russia are considered highly inflationary economies. As a result, operations in those countries are re-measured in United States dollars, and all currency gains or losses are recorded in the statement of income. We attempt to manage our operations in a manner to reduce our exposure to foreign exchange losses. However, there are many factors which affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. 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 United States dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates. FINANCIAL INSTRUMENTS Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, marketable securities and accounts receivable. Our short-term investments are placed with a variety of financial institutions with high credit ratings. This diversified investment policy limits our exposure both to credit risk and to concentrations of credit risk. Accounts receivable result from oil and natural gas exploration and production activities and our customers and partners are engaged in the oil and natural gas business. PDVSA Petroleo y Gas, S.A. ("PDVSA"), an affiliate of Petroleos de Venezuela, S.A., purchases 100 percent of our Venezuelan oil production. Although the Company does not currently foresee a credit risk associated with these receivables, repayment is dependent upon the financial stability of PDVSA. Our financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, marketable securities, short-term borrowings and long-term debt. The book values of all financial instruments, other than long-term debt, are representative of their fair values due to their short-term maturities. The aggregate fair value of our senior unsecured notes, based on the last trading prices at December 31, 2000 and 1999, was approximately $137.0 million and $151.0 million, respectively. TREASURY STOCK In June 1997, our Board of Directors instituted a treasury stock repurchase program under which we are authorized to purchase up to 1.5 million shares of our common stock. The shares may be used for reissuance in connection with the Company's employee stock option plan or for other corporate purposes. During 1997, we repurchased 50,000 shares at an average price of $13.99 per share. 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 years ended December 31, 2000 and, in accordance with SFAS 130, have not provided a separate statement of comprehensive income. DERIVATIVES AND HEDGING Statement of Financial Accounting Standards No. 133 ("SFAS 133"), as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. The Company has not used derivative or hedging instruments since 1996, but may consider hedging some portion of its oil production in the future. The Company does not believe, however, that the adoption of SFAS 133 will have a material effect on its results of operations or financial position. MINORITY INTERESTS We record a minority interest attributable to the minority shareholders of our Venezuela subsidiaries. The minority interests in net income and losses are generally subtracted or added to arrive at consolidated net income. However, as of December 31, 1998, losses attributable to S-9 53 53 the minority shareholder of Benton-Vinccler, our 80 percent owned subsidiary, exceeded its interest in equity capital creating an equity deficit of $3.5 million. Accordingly, $3.5 million of income attributable to the minority shareholder of Benton-Vinccler in 1999 was included in our consolidated net loss, eliminating the minority shareholder's equity deficit. USE OF ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. RECLASSIFICATIONS Certain items in 1999 and 1998 have been reclassified to conform to the 2000 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 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. Investment in equity in net assets of Geoilbent includes our capital contribution of $2.0 million in December 1998 which was included in other costs, net of amortization. During 1998, due to declines in world oil prices, we recorded a write-down of $10.1 million related to the Geoilbent investment. No dividends have been paid to us from Geoilbent or Arctic Gas. Equity in earnings and losses and investments in and advances to companies accounted for using the equity method are as follows (in thousands):
GEOILBENT, LTD. ARCTIC GAS COMPANY TOTAL --------------- ------------------ ----- 2000 1999 2000 1999 2000 1999 ---- ---- ---- ---- ---- ---- Investments: In equity in net assets......... $ 28,056 $ 28,056 $ (2,218) $ (2,419) $ 25,838 $ 25,637 Other costs, net of amortization (202) (542) 19,058 17,128 18,856 16,586 ---------- ---------- --------- ----------- --------- --------- Total investments............... 27,854 27,514 16,840 14,709 44,694 42,223 Advances............................ - - 21,986 13,364 21,986 13,364 Equity in earnings (losses)......... 12,310 6,167 (1,249) (397) 11,061 5,770 ---------- ---------- --------- ----------- --------- --------- Total........................ $ 40,164 $ 33,681 $ 37,577 $ 27,676 $ 77,741 $ 61,357 ========== ========== ========= =========== ========= =========
NOTE 3 - LONG-TERM DEBT AND LIQUIDITY LONG-TERM DEBT Long-term debt consists of the following at December 31 (in thousands):
2000 1999 ---- ---- Senior unsecured notes with interest at 9.375%...................................... $ 105,000 $ 105,000 Senior unsecured notes with interest at 11.625%..................................... 108,000 125,000 Benton-Vinccler credit facility with interest at LIBOR plus 6.125%. Collateralized by a time deposit earning approximately LIBOR plus 5.75% - See description below.......................... - 34,575 Other ........................................................................... - 2 ----------- ----------- 213,000 264,577 Less current portion................................................................ - 2 ----------- ----------- $ 213,000 $ 264,575 =========== ===========
S-10 54 54 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. 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 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. In addition, we wrote-off $0.2 million in unamortized loan fees related to the notes resulting in an extraordinary gain of $4.0 million. 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. At December 31, 2000, we were in compliance with all covenants of the indentures. In August 1996, Benton-Vinccler entered into a $50 million, long-term credit facility with Morgan Guaranty Trust Company of New York ("Morgan Guaranty") to repay the balance outstanding under a short-term credit facility and to repay certain advances received from us. In August 1999, Benton-Vinccler repaid $15.4 million of the long-term credit facility with proceeds from the sale of certain equipment located in the South Monagas Unit (see Note 10) and in October 2000 Benton-Vinccler reduced the credit facility to $31.6 million. In December 2000, the credit facility was fully repaid. The principal payment requirements for our long-term debt outstanding at December 31, 2000 are as follows (in thousands): 2001............................................... $ - 2002............................................... - 2003............................................... 108,000 2004............................................... - 2005............................................... - Subsequent Years................................... 105,000 ----------- $ 213,000 =========== In March 2001, Benton-Vinccler borrowed $12.3 million, 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 5 years. The second loan, in the amount of 4.4 billion Venezuelan Bolivars ($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 initial quarterly period is 16.5%. LIQUIDITY As a result of Benton's increased leverage and poor investment returns since 1998, 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 aimed at creating new stockholder value, we undertook several significant actions beginning in 2000, including: - Hired a new President and Chief Executive Officer, a new Senior Vice President and Chief Financial Officer and a new Vice President and General Counsel; - Reconstituted our Board of Directors with industry executives with proven experience in oil and natural gas operations, finance and international operations; - Redefined our strategic priorities to focus on value creation; - Initiated capital conservation steps and financial transactions to de-leverage the company and improve cash flow for reinvestment; - Undertook a comprehensive study of our core Venezuelan asset to attempt to enhance the value of its production, thus ultimately increasing cash flow and potentially extending its productive life. We continue to aggressively explore means by which to maximize stockholder value. We believe that Benton possesses significant producing properties in Venezuela which have yet to be optimized and valuable unexploited acreage in Venezuela and Russia. The intrinsic value of Benton's assets is burdened by a heavy debt load and constraints on capital to further exploit such opportunities. Therefore, we, with the advice of its financial and legal advisors, are conducting a comprehensive review of strategic alternatives, including, but not limited to, selling all or part of its existing assets in Venezuela and Russia, debt restructuring, some combination thereof, 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. S-11 55 55 As a result of the decline in oil prices, we instituted in 1998, and continued in 1999, 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 increased substantially and we concluded an analysis of our strategic alternatives. 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 Note10). During 2000, we drilled 26 oil wells in the Uracoa Field under the alliance agreements utilizing Schlumberger's technical and engineering resources. While no assurance can be given, we currently believe that our capital resources and liquidity will be adequate to fund our planned capital expenditures, investments in and advances to affiliates and semiannual interest payment obligations for the next twelve (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 is a significant decrease in either price or production levels related to the South Monagas Unit. Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well as various economic conditions that have historically affected the oil and natural gas business. Prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond our control. 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. The current interest rate on the facility is 16.5 percent. In December 2000, we borrowed 4 billion Bolivars (approximately $5.7 million) under this facility at an interest rate of 12.5 percent, which we repaid in January 2001. 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 shareholders 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 shareholders 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 filed suit in the Unites 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 have been filed. We believe that this case lacks merit and that an unfavorable outcome is unlikely. In the normal course of our business, we may periodically become subject to actions threatened or brought by our investors or partners in connection with the operation or development of our properties or the sale of securities. We are also subject to ordinary litigation that is incidental to our business, none of which is expected to have a material adverse effect on our financial position, results of operations or liquidity. S-12 56 56 In May 1996, we entered into an agreement with Morgan Guaranty that provided for an $18 million cash collateralized 5-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 as of December 31, 2000. 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 November 1997, we entered into an agreement with Morgan Guaranty which provided for a $1 million cash collateralized 2-year letter of credit, which was extended to November 2000, to secure our obligations under the first exploration phase of a Production Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") (see Note 13). At the May 17, 2000 expiration date of the PSA, we had not completed our obligation under the first exploration phase of the agreement. As a result, the NRA collected on the letter of credit in August 2000. 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 also entered into employment agreements with three individuals, which provide for certain severance payments in the event of a change of control of our company and subsequent termination by the employees for good reason. 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 9). 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 separate building for approximately $76,000 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 $50,000 per month. Our aggregate rental commitments for non-cancellable agreements at December 31, 2000 are as follows (in thousands):
MINIMUM LEASE SUBLEASE COMMITMENTS INCOME ----------- ------ 2001................................................ $ 1,661 $ 978 2002................................................ 1,400 1,005 2003................................................ 1,435 1,032 2004................................................ 1,449 849 2005................................................ 1,074 - Thereafter.......................................... 9,284 - ----------- ----------- $ 16,303 $ 3,864 =========== ===========
Rental expense was $2.2 million, $2.5 million and $2.0 million for the years ended December 31, 2000, 1999 and 1998, respectively. Sublease income was $1.1 million, $1.0 million and $0.3 million for the years ended December 31, 2000, 1999 and 1998, respectively. 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. Any compensation from PDVSA related to this matter will be recorded in the period in which PDVSA confirms our claim. S-13 57 57 NOTE 5 - TAXES TAXES OTHER THAN ON INCOME Benton-Vinccler pays a municipal tax of approximately 2.6 percent on operating fee revenues it receives for production from the South Monagas Unit. The components of taxes other than on income were (in thousands):
2000 1999 1998 ---- ---- ---- Venezuelan municipal taxes ............................... $3,164 $2,303 $2,109 Severance and production taxes ........................... 28 - - Franchise taxes .......................................... 131 139 151 Payroll and other taxes .................................. 1,067 1,371 1,417 ------ ------ ------ $4,390 $3,813 $3,677 ====== ====== ======
TAXES ON INCOME The tax effects of significant items comprising our net deferred income taxes as of December 31, 2000 and 1999 are as follows (in thousands):
2000 1999 ---- ---- Deferred tax assets: Operating loss carryforwards ........................................... $ 37,142 $ 36,242 Difference in basis of property ........................................ 4,948 13,040 Other .................................................................. 16,410 14,817 Valuation allowance .................................................... (54,207) (51,913) -------- -------- Net deferred tax asset ..................................................... $ 4,293 $ 12,186 ======== ========
The valuation allowance increased by $1.0 million and decreased by $8.1 million as a result of the increase in the U.S. deferred tax assets related to the net operating loss carryforward and to property, respectively. We have determined that it is more likely than not that these U.S. deferred tax assets will not be realized. The components of income before income taxes, minority interest and extraordinary items are as follows (in thousands):
2000 1999 1998 ---- ---- ---- Income (loss) before income taxes United States ................................................ $(13,033) $(38,637) $ (50,637) Foreign ...................................................... 51,463 (236) (180,749) -------- -------- --------- Total ..................................................... $ 38,430 $(38,873) $(231,386) ======== ======== =========
The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
2000 1999 1998 ---- ---- ---- Current: United States ...................................................... $ 215 $ (2,216) $ 1,470 Foreign ............................................................ 5,925 3,900 1,406 -------- -------- --------- 6,140 1,684 2,876 -------- -------- --------- Deferred: United States ...................................................... - - 3,573 Foreign ............................................................ 7,892 (9,210) (31,360) -------- -------- --------- 7,892 (9,210) (27,787) -------- -------- --------- $ 14,032 $ (7,526) $ (24,911) ======== ======== =========
S-14 58 58 A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):
2000 1999 1998 ---- ---- ---- Computed tax expense at the statutory rate ................... $ 13,451 $(13,606) $(80,985) State income taxes, net of federal effect .................... (343) (307) 112 Effect of foreign source income and rate differentials on foreign income ............................................ (1,826) 4,507 23,987 Change in valuation allowance ................................ 2,294 5,951 32,121 Prior year adjustments ....................................... 1,637 (847) (1,917) Effect of tax law changes .................................... - (2,220) - All other .................................................... 679 - - -------- -------- -------- Sub-total income tax expense (benefit) ....................... 15,892 (6,522) (26,682) Effects of recording equity income of certain affiliated Companies on an after-tax basis ........................... (1,860) (1,004) 1,771 -------- -------- -------- Total income tax expense (benefit) ........................... $ 14,032 $ (7,526) $(24,911) ======== ======== ========
Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign jurisdictions and from the effect of foreign currency devaluation in foreign subsidiaries which use the U.S. dollar as their functional currency. The effect of tax law changes relates to benefits from the Venezuela-United States tax treaty ratified in 1999. 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. 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. NOTE 6 - STOCK OPTION AND STOCK PURCHASE PLANS During 1989, we adopted our 1989 Nonstatutory Stock Option Plan covering 2,000,000 shares of common stock which were granted to key employees, directors, independent contractors and consultants at prices equal to or below market prices, exercisable over various periods. The plan was amended during 1990 to add 1,960,000 shares of common stock. In September 1991, we adopted the 1991-1992 Stock Option Plan and the Directors' Stock Option Plan. The 1991-1992 Stock Option Plan, as amended in 1996 and 1997, permitted the granting of stock options to purchase up to 4,800,000 shares of the Company's common stock in the form of ISOs and NQSOs to our officers and employees of the Company. Options could be granted as ISOs, NQSOs or a combination of each, with exercise prices not less than the fair market value of the common stock on the date of the grant. The amount of ISOs that may be granted to any one participant is subject to the dollar limitations imposed by the Internal Revenue Code of 1986, as amended. In the event of a change in control of our company, all outstanding options become immediately exercisable to the extent permitted by the 1991-1992 Stock Option Plan. All options granted to date under the plan vest ratably over a three-year period from their dates of grant and expire ten years from grant date or one year after retirement, if earlier. Subsequent to shareholder approval of the 1998 Stock-Based Incentive Plan discussed below, our Board of Directors terminated future grants under the 1991-1992 Stock Option Plan. The Directors' Stock Option Plan permitted the granting of nonqualified stock options ("Director NQSOs") to purchase up to 400,000 shares of common stock to our nonemployee directors. Upon election as a director and annually thereafter, each individual who served as a nonemployee director was automatically granted an option to purchase 10,000 shares of common stock at a price not less than the fair market value of common stock on the date of grant. All Director NQSOs vested automatically on the date of the grant of the options, and at December 31, 2000, options to purchase 310,000 shares of common stock were both outstanding and exercisable. The Director stock option plan has been replaced with the Non-Employee Director Stock Purchase Plan. No additional Director NQSO's will be granted under the Directors Stock Option Plan. In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the "Stock Purchase Plan") to encourage our directors to acquire a greater proprietary interest in our company through the ownership of our common stock. Each non-employee director may elect once each year, prior to January 1, to be effective for the following year and until a new election is made, to receive shares of our common S-15 59 59 stock for all or a portion of their fee for serving as a director. The number of shares issuable will be equal to 1.5 times the amount of cash compensation due the director divided by the fair market value of the common stock on the scheduled date of payment of the applicable director's fee. The shares will have a restriction upon their sale for one year from the date of issuance. In June 1998, our shareholders approved the adoption of the 1998 Stock-Based Incentive Plan. The 1998 Stock-Based Incentive Plan authorizes up to 1,400,000 shares of our common stock for grants of NQSOs and ISOs, stock appreciation rights, restricted stock awards and bonus stock awards to our employees or employees of our subsidiaries or associated companies. The exercise price of stock options granted under the plan must be no less than the fair market value of our common stock on the date of grant. The total number of shares for which awards may be made to any one participant during any calendar year cannot exceed 500,000 shares, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control of our company, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date under the 1998 Stock-Based Incentive Plan vest ratably over a three-year period from their dates of grant and expire ten years from grant date or one year after retirement, if earlier. In November 1999, we adopted the 1999 Stock Option Plan. The 1999 Stock Option Plan permits the granting of stock options to purchase up to 2,500,000 shares of our common stock in the form of ISOs and NQSOs to directors, employees and consultants. Options may be granted as ISOs, NQSOs or a combination of each, with exercise prices not less than the fair market value of the common stock on the date of the grant. The amount of ISOs that may be granted to any one participant is subject to the dollar limitations imposed by the Internal Revenue Code of 1986, as amended. In the event of a change in control of our company, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date to employees under the 1999 Stock Option Plan vest 50 percent after the first year and 25 percent after each of the following two years from their dates of grant and expire ten years from grant date or three months after retirement, if earlier. All options granted to outside directors and consultants under the 1999 Stock Option Plan vest ratably over a three-year period from their dates of grant and expire ten years from grant date. A summary of the status of our stock option plans as of December 31, 2000, 1999 and 1998 and changes during the years ending on those dates is presented below (shares in thousands):
2000 1999 1998 ---- ---- ---- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE PRICE SHARES PRICE SHARES PRICE SHARES ----- ------ ----- ------ ----- ------ Outstanding at beginning of the year:......... $ 7.55 6,300 $ 11.27 3,712 $ 11.78 3,563 Options granted............................... 2.06 240 2.37 2,701 8.62 513 Options exercised............................. 2.53 (85) - - 7.77 (81) Options cancelled............................. 4.90 (795) 6.10 (113) 13.88 (283) -------- -------- ------- Outstanding at end of the year................ 7.74 5,660 7.55 6,300 11.27 3,712 ======== ======== ======= Exercisable at end of the year................ 9.68 4,099 11.23 3,251 10.63 2,648 ======== ======== =======
Significant option groups outstanding at December 31, 2000 and related weighted average price and life information follow (shares in thousands):
RANGE OF NUMBER WEIGHTED-AVERAGE NUMBER EXERCISE OUTSTANDING AT REMAINING WEIGHTED-AVERAGE EXERCISABLE AT WEIGHTED-AVERAGE PRICES DECEMBER 31, 2000 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 2000 EXERCISE PRICE ------ ----------------- ---------------- -------------- ----------------- -------------- $ 1.88-2.75 2,546 8.7 Years $2.33 1,083 $ 2.31 4.89-7.00 409 3.8 Years 6.19 401 6.19 7.25-11.00 1,093 3.6 Years 8.87 1,003 8.88 11.50-16.50 1,081 5.9 Years 13.59 1,081 13.59 17.38-24.13 531 6.1 Years 20.90 531 20.90 ---------- ------- 5,660 4,099 ========== =======
S-16 60 60 The weighted average fair value of the stock options granted from the 1988 Stock-Based Incentive Plan, 1991-1992, 1998 and 1999 Stock Option Plans and the Directors' Stock Option Plan during 2000, 1999 and 1998 was $1.65, $1.88 and $6.30 respectively. The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used:
2000 1999 1998 ---- ---- ---- Expected life....................................... 9.1 years 9.3 years 9.1 years Risk-free interest rate............................. 6.1% 5.9% 5.5% Volatility.......................................... 74% 73% 62% Dividend Yield...................................... 0% 0% 0%
We account for stock-based compensation in accordance with Accounting Principles Board Opinion No. 25 and related interpretations, under which no compensation cost has been recognized for stock option awards. Had compensation cost for the plans been determined consistent with SFAS 123, our pro forma net income and earnings per share for 2000, 1999 and 1998 would have been as follows (in thousands, except per share data):
2000 1999 1998 ---- ---- ---- Net income (loss)...................................... $ 16,224 $ (38,441) $ (190,581) ======== ========== ========== Net income (loss) per common share: Basic............................................... $ 0.53 $ (1.30) $ (6.45) ======== ========== ========== Diluted............................................. $ 0.53 $ (1.30) $ (6.45) ======== ========== ==========
In connection with our acquisition of Benton Offshore China Company in December 1996, we adopted the Benton Offshore China Company 1996 Stock Option Plan. Under the plan, Benton Offshore China Company is authorized to issue up to 107,571 options to purchase our common stock for $7.00 per share. The plan was adopted in substitution of Benton Offshore China Company's stock option plan, and all options to purchase shares of Benton Offshore China Company common stock were replaced under the plan by options to purchase shares of our common stock. All options were issued upon the acquisition of Benton Offshore China Company and vested upon issuance. At December 31, 2000, options to purchase 74,427 shares of common stock were both outstanding and exercisable. In addition to options issued pursuant to the plans, options have been issued to individuals other than officers, directors or employees of the Company at prices ranging from $10.88 to $11.88 which vest over three to four years. At December 31, 2000, a total of 208,500 options issued outside of the plans were both outstanding and exercisable. Our expenses associated with these options were not material. NOTE 7 - STOCK WARRANTS During the years ended December 31, 1996, 1995 and 1994, we issued a total of 587,783, 125,000 and 450,000 warrants, respectively. Each warrant entitles the holder to purchase one share of common stock at the exercise price of the warrant. Substantially all the warrants are immediately exercisable upon issuance. In January 1996, 587,783 warrants were issued in connection with an exchange offer under which we acquired the outstanding limited partnership interests in three limited partnerships we sponsored. During the years ended December 31, 1997 and 1996, 1,578 and 9,215, respectively, of the warrants were exercised. In November 1998, 1999 and again in December 2000, we extended by one year the expiration date of these warrants, which now will expire on January 18, 2002. We recorded $135,000, $24,000, and $12,000 of expense in 1998, 1999 and 2000, respectively, as a result of these warrant extensions. In June 1995, 125,000 warrants were issued in connection with the issuance of $20 million of senior unsecured notes. In July 1994, we issued warrants entitling the holder to purchase a total of 150,000 shares of common stock at $7.50 per share, subject to adjustment in certain circumstances that are exercisable on or before July 2004, 50,000 warrants were immediately exercisable, and 50,000 warrants became exercisable each July in 1995 and 1996. During the year ended December 31, 1996, 142,000 of these warrants were exercised. In September 1994, 250,000 warrants were issued in connection with the issuance of $15 million of senior unsecured notes, and in December 1994, 50,000 warrants were issued in connection with a revolving secured credit facility. S-17 61 61 The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at December 31, 2000 were (shares in thousands):
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING ----------- --------------- -------------- ------ ----------- July 1994 July 2004 $ 7.50 150 8 September 1994 September 2002 9.00 250 250 December 1994 December 2004 12.00 50 50 June 1995 June 2007 17.09 125 125 January 1996 January 2002 11.00 588 577 ------- -------- 1,163 1,010 ======= ========
S-18 62 62 NOTE 8 - OPERATING SEGMENTS We regularly allocate resources to and assesses 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 Russia operating segments are derived primarily from the production and sale of oil. Other income from USA and other is derived primarily from interest earnings on various investments and consulting revenues. Operations included under the heading "USA and Other" include corporate management, exploration 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, other income and equity earnings, 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.
YEAR ENDED DECEMBER 31, 2000: (in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED --------- ------------- -------- ------------- ------------ Revenues Oil and natural gas sales .......................... $ 139,890 $ 394 $ - $ - $ 140,284 --------- --------- -------- --------- --------- 139,890 394 - - 140,284 --------- --------- -------- --------- --------- Expenses Operating expenses ................................. 46,727 59 644 - 47,430 Depletion, depreciation and amortization ........... 16,285 879 11 - 17,175 General and administrative ......................... 3,659 12,014 1,066 - 16,739 Taxes other than on income ......................... 3,355 1,048 (13) - 4,390 --------- --------- -------- --------- --------- Total expenses ............................... 70,026 14,000 1,708 - 85,734 --------- --------- -------- --------- --------- Income (loss) from operations .......................... 69,864 (13,606) (1,708) - 54,550 Other non-operating income (expense): Investment earnings and other ...................... 1,392 8,986 - (1,819) 8,559 Interest expense ................................... (6,131) (24,661) - 1,819 (28,973) Net gain on exchange rates ......................... 298 28 - - 326 Intersegment revenues (expenses) ................... (12,226) 12,226 - - - Equity in income of affiliated companies ........... - - 5,313 - 5,313 --------- --------- -------- --------- --------- (16,667) (3,421) 5,313 - (14,775) --------- --------- -------- --------- --------- Income (loss) before income taxes ...................... 53,197 (17,027) 3,605 - 39,775 Income tax expense ..................................... 14,020 12 - - 14,032 --------- --------- -------- --------- --------- Operating segment income (loss) ........................ 39,177 (17,039) 3,605 - 25,743 Write-down of oil and gas properties and impairments ... - (1,346) - - (1,346) Minority interest ...................................... (7,869) - - - (7,869) Extraordinary income on debt repurchase ................ - 3,960 - - 3,960 --------- --------- -------- --------- --------- Net income (loss) ...................................... $ 31,308 $ (14,425) $ 3,605 $ - $ 20,488 ========= ========= ======== ========= ========= Total assets ........................................... $ 166,462 $ 156,780 $ 78,406 $(115,201) $ 286,447 ========= ========= ======== ========= ========= YEAR ENDED DECEMBER 31, 1999: (in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED --------- -------------- -------- ------------ ------------ Revenues Oil and natural gas sales .......................... $ 89,060 $ - $ - $ - $ 89,060 --------- --------- -------- -------- --------- 89,060 - - - 89,060 --------- --------- -------- -------- --------- Expenses Operating expenses ................................. 38,683 34 676 -- 39,393 Depletion, depreciation and amortization ........... 15,705 801 13 - 16,519 General and administrative ......................... 4,482 19,729 1,758 - 25,969 Taxes other than on income ......................... 2,501 1,326 (14) - 3,813 --------- --------- -------- -------- --------- Total expenses ............................... 61,371 21,890 2,433 - 85,694 --------- --------- -------- -------- --------- Income (loss) from operations .......................... 27,689 (21,890) (2,433) - 3,366 Other non-operating income (expense) Investment earnings and other ...................... 758 9,510 2 (1,284) 8,986 Interest expense ................................... (6,834) (23,697) - 1,284 (29,247) Net gain on exchange rates ......................... 1,033 11 - - 1,044 Intersegment revenues (expenses) ................... (8,906) 8,906 - - - Equity in income of affiliated companies ........... - - 2,869 - 2,869 --------- --------- -------- -------- --------- (13,949) (5,270) 2,871 - (16,348) --------- --------- -------- -------- --------- Income (loss) before income taxes ...................... 13,740 (27,160) 438 - (12,982) Income tax expense (benefit) ........................... (7,554) (170) 198 - (7,526) --------- --------- -------- -------- --------- Operating segment income (loss) ........................ 21,294 (26,990) 240 - (5,456) Write-down of oil and gas properties and impairments ... - (25,891) - - (25,891) Minority interest ...................................... (937) - - - (937) --------- --------- -------- -------- --------- Net income (loss) ...................................... $ 20,357 $ (52,881) $ 240 $ - $ (32,284) ========= ========= ======== ======== ========= Total assets ........................................... $ 124,942 $ 188,000 $ 61,989 $(98,620) $ 276,311 ========= ========= ======== ======== =========
S-19 63 63
YEAR ENDED DECEMBER 31, 1998: (in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED --------- ------------- --------- ------------ ------------ Revenues Oil and natural gas sales ........................ $ 82,215 $ (3) $ - $ - $ 82,212 --------- --------- --------- --------- --------- 82,215 (3) - - 82,212 --------- --------- --------- --------- --------- Expenses Operating expenses ............................... 38,905 (20) 1,181 - 40,066 Depletion, depreciation and amortization ......... 32,532 625 - - 33,157 General and administrative ....................... 4,505 16,662 318 - 21,485 Taxes other than on income ....................... 2,315 1,362 - - 3,677 --------- --------- --------- --------- --------- Total expenses ............................. 78,257 18,629 1,499 - 98,385 --------- --------- --------- --------- --------- Income (loss) from operations ........................ 3,958 (18,632) (1,499) - (16,173) Other non-operating income (expense) Investment earnings and other .................... 806 14,014 67 (905) 13,982 Interest expense ................................. (7,261) (25,651) - 905 (32,007) Net gain on exchange rates ....................... 1,741 26 - - 1,767 Intersegment revenues (expenses) ................. (8,211) 8,211 - - - Equity in loss of affiliated companies ........... - - (5,062) - (5,062) --------- --------- --------- --------- --------- (12,925) (3,400) (4,995) - (21,320) --------- --------- --------- --------- --------- Loss before income taxes ............................. (8,967) (22,032) (6,494) - (37,493) Income tax expense (benefit) ......................... (29,955) 5,044 - - (24,911) --------- --------- --------- --------- --------- Operating segment income (loss) ...................... 20,988 (27,076) (6,494) - (12,582) Write-down of oil and gas properties and impairments . (187,811) (6,082) - - (193,893) Minority interest .................................... 22,895 - - - 22,895 --------- --------- --------- --------- --------- Net loss ............................................. $(143,928) $ (33,158) $ (6,494) $ - $(183,580) ========= ========= ========= ========= =========
S-20 64 64 NOTE 9 - RUSSIAN OPERATIONS GEOILBENT, LTD. We own 34 percent of Geoilbent, Ltd., a Russian limited liability company formed in 1991 to develop, produce and market crude oil from the North Gubkinskoye Field in the West Siberia region of Russia. Geoilbent also holds rights to three additional license blocks. Our investment in Geoilbent is accounted for using the equity method. Sales quantities attributable to Geoilbent for the years ended December 31, 2000, 1999 and 1998 were 4,247,590 Bbls, 4,267,647 Bbls and 2,716,476 Bbls, respectively. Prices for crude oil for the years ended December 31, 2000, 1999 and 1998 averaged $17.45, $7.68 and $8.72 per barrel, respectively. Depletion expense attributable to Geoilbent for the years ended December 31, 2000, 1999 and 1998 was $2.29, $2.27 and $3.69 per barrel, respectively. Summarized financial information for Geoilbent follows (in thousands). All amounts represent 100 percent of Geoilbent.
YEAR ENDED SEPTEMBER 30: 2000 1999 1998 ---- ---- ---- Revenues Oil sales.................................................... $ 74,123 $ 32,770 $ 23,703 ----------- ----------- ----------- 74,123 32,770 23,703 ----------- ----------- ----------- Expenses Operating expenses........................................... 9,798 4,364 6,863 Depletion, depreciation and amortization..................... 9,557 9,669 10,020 General and administrative................................... 3,407 2,655 3,326 Taxes other than on income................................... 18,286 8,208 6,210 ----------- ----------- ----------- 41,048 24,896 26,419 ----------- ----------- ----------- Income (loss) from operations.................................... 33,075 7,874 (2,716) Other non-operating income (expense) Investment earnings and other................................ (543) 6,527 18,023 Interest expense............................................. (8,145) (3,572) (2,648) ----------- ----------- ----------- (8,688) 2,955 15,375 ----------- ----------- ----------- Income before income taxes....................................... 24,387 10,829 12,659 Income tax expense............................................... 6,321 1,333 562 ----------- ----------- ----------- Net income ...................................................... $ 18,066 $ 9,496 $ 12,097 =========== =========== =========== 2000 1999 1998 ---- ---- ---- AT SEPTEMBER 30: Current assets................................................... $ 30,070 $ 25,699 $ 7,876 Other assets..................................................... 163,219 139,488 129,037 Current liabilities.............................................. 32,700 10,276 15,772 Other liabilities................................................ 41,866 54,254 33,999 Net equity....................................................... 118,723 100,657 87,142
S-21 65 65 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 achieving certain reserve and production milestones, under parallel reserve-based loan agreements. Under these loan agreements, we 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 interest rate of 15 percent payable on January 27 and July 27 each year. Principal payments will be due in varying installments on the semiannual interest payment dates beginning January 27, 2001 and ending by 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 September 30, 2000. The proceeds from the loans were used by Geoilbent to develop the North Gubkinskoye and Prisklonovoye Fields in West Siberia, Russia. The principal payment requirements for the long-term debt of Geoilbent at September 30, 2000 are as follows for the years ending September 30 (in thousands): 2001................................................ $ 10,455 2002................................................ 16,000 2003................................................ 11,000 2004................................................ 11,000 2005................................................ - Subsequent Years.................................... - ---------- $ 48,455 ========== 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, with the agreement of EBRD, Geoilbent ratified an agreement to reimburse us for $2.6 million of such costs, which were included in accounts receivable. However, due to Geoilbent's need for oil and natural gas investment and the declining prices for crude oil, in the second quarter of 1998, we agreed to defer payment of those reimbursements. We received the $2.6 million during 2000. 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. The credit facility is renewable annually. Loans outstanding under the credit facility bear interest at either LIBOR plus 0.75 percent, subject to certain adjustments, or the Morgan Guaranty prime rate plus 2 percent, whichever is selected at the time a loan is made. In conjunction with Geoilbent's reserve-based loan agreements with EBRD and IMB, repayment of the credit facility was subordinated to payments due to EBRD and IMB and, accordingly, the credit facility was reclassified from current to long-term in 1998. The credit facility contains no restrictive covenants and no financial ratio covenants. At December 31, 2000, $3.2 million was outstanding under the credit facility. Excise, pipeline and other tariffs and taxes continue to be levied on all oil producers and certain exporters, including an oil export tariff that increased to 34 Euros per ton (approximately $3.80 per barrel) on November 3, 2000 from 15 Euros per ton in 1999. 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, formerly Severneftegaz. 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 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 December 31, 2000, we had loaned $22.0 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 9 percent equity interest. From December 1998 through November 2000, we purchased shares representing an additional 20 percent equity interest not subject to any sale or transfer restrictions. We owned a total of 60 percent of the outstanding voting shares of Arctic Gas as of December 31, 2000, of which approximately 29 percent were not subject to any restrictions. S-22 66 66 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 $0.7 million and $0.4 million for the years ended September 30, 2000 and 1999, respectively. Our weighted-average equity interest, not subject to any sale or transfer restrictions for the years ended December 31, 2000 and 1999 was 24 percent and 12 percent, respectively. 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. Arctic Gas began selling oil in June 2000. Summarized financial information for Arctic Gas follows (in thousands). All amounts represent 100 percent of Arctic Gas.
YEAR ENDED SEPTEMBER 30: 2000 1999 ---- ---- Revenues Oil Sales................................. $ 3,354 $ - ----------- ----------- 3,354 - ----------- ----------- Expenses Operating expense......................... 1,004 - Depletion, depreciation and amortization.. 432 85 General and administrative................ 2,154 2,941 Taxes other than on income................ 1,422 64 ----------- ----------- 5,012 3,090 ----------- ----------- Loss from operations......................... (1,658) (3,090) Other non-operating income (expense) Other income (expense).................... (14) 585 Interest expense.......................... (1,558) (868) ----------- ----------- (1,572) (283) ----------- ----------- Loss before income taxes..................... (3,230) (3,373) Income tax expense........................... 188 - ----------- ----------- Net loss..................................... $ (3,418) $ (3,373) =========== =========== AT SEPTEMBER 30: 2000 1999 ---- ---- Current assets............................... 1,205 1,513 Other assets................................. 10,120 5,043 Current liabilities.......................... 23,955 18,068 Other liabilities............................ - - Net equity................................... (12,630) (11,512)
NOTE 10 - 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 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, 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 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. S-23 67 67 In August 1999, Benton-Vinccler sold its recently-constructed power generation facility located in the Uracoa Field of the South Monagas Unit in Venezuela for $15.1 million. Concurrently with the sale, Benton-Vinccler entered into a long-term power purchase agreement with the purchaser of the facility to provide for the electrical needs of the field throughout the remaining term of the operating service agreement. Benton-Vinccler used the proceeds from the sale to repay indebtedness that was collateralized by a time deposit made by us. Permanent repayment of a portion of the loan allowed us to reduce the cash collateral for the loan thereby making the cash available for working capital needs. In December 1999, we and Benton-Vinccler 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 wells have been drilled under the alliance program. 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 completing an 839 square kilometer seismic survey and drilling three wells to the depths of 12,000 to 18,000 feet 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 have a 30 percent interest in the exploration venture, with Burlington and Anadarko each owning a 35 percent interest. Under the terms of the operating agreement, which establishes the management company of the project, Burlington is the operator of the field and, therefore, we are not able to exercise control of the operations of the venture. Corporacion Venezolana del Petroleo, S.A., an affiliate of PDVSA, has the right to obtain a 35 percent interest in the management company, which dilutes the voting power of the partners on a pro rata basis. 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). As of December 31, 1998, our share of expenditures was $8.2 million, which was included in the Venezuela cost center after evaluation for proved reserves, and the standby letter of credit had been reduced to $11.2 million. During 1999, the Block's first exploration well, the Jarina 1-X, penetrated a thick potential reservoir sequence, but encountered no hydrocarbons. As of December 31, 2000, our share of the total expenditures was $15.4 million. 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, in January 2001, we included $7.7 million of restricted cash that collateralized the letter of credit in the Venezuelan full cost pool. While the Venezuela cost center experienced a full cost ceiling test write-down of $187.8 million in 1998, there have been no further impairments. NOTE 11 - 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 natural 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 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 Bbls 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 cash and a 5 percent carried working interest in up to four wells that may be drilled in the future. 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 S-24 68 68 capitalized costs associated with the California Leases of $9.2 million and the joint interest receivable of $3.1 million due from Molino Energy at December 31, 1999. NOTE 12 - 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 will, as our wholly owned subsidiary, continue 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. In October 1997, we signed a farmout agreement with Shell Exploration (China) Limited ("Shell") whereby we acquired a 50 percent participation interest in Shell's Liaohe area onshore exploration project in northeast China. Shell held a petroleum contract with China National Petroleum Corporation ("CNPC") to explore and develop the deep rights in the Qingshui Block, approximately 140,000 acres (563 square kilometers), in the delta of the Liaohe River. Shell was the operator of the project. In July 1998, we paid to Shell 50 percent of Shell's prior investment in the Block, which was approximately $4 million ($2 million to us). Pursuant to the farmout agreement, we were required to pay 100 percent of the first $8 million of the costs for the phase one exploration period, after which any development costs were to be shared equally. During the first six months of 1999, the first exploratory well on the Qingshui Block was drilled to a total depth of 4,500 meters, and two reservoirs, the Sha-2 and Sha-3, were tested. Although hydrocarbons were encountered during drilling of the Qing Deep 22, we and operator Shell concluded that the well was non-commercial. As a result, we elected not to continue to the second exploration phase and have relinquished our interest in the Block. Accordingly, we recognized a write-down of the capitalized cost related to the farmout agreement of $12.6 million in the third quarter of 1999. NOTE 13 - JORDAN OPERATIONS In August 1997, we acquired the rights to an Exploration and Production Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to explore, develop and produce the Sirhan Block in southeastern Jordan. Under the terms of the PSA, we were obligated to make certain capital and operating expenditures in up to three phases over eight years. We were obligated to spend $5.1 million in the first exploration phase, which was extended to May 2000, for which we posted a $1 million standby letter of credit, collateralized in full by a time deposit. During the first quarter of 1998, we reentered two wells and tested two different reservoirs. The WS-9 well tested significant, but non-commercial amounts of natural gas; the WS-10 well resulted in no commercial amounts of hydrocarbons. Therefore, at December 31, 1998, we wrote down $3.7 million in capitalized costs incurred to date related to the PSA. During 1999, we incurred an additional $0.3 million in capitalized costs, which were written off at December 31, 1999. As of the May 17, 2000 expiration date of the PSA, we had elected not to complete the first exploration phase of the agreement. As a result, during the second quarter of 2000, we recorded a liability to the NRA for the obligation remaining under the PSA resulting in impairment expense of $1.0 million. The NRA collected on the letter of credit in August 2000. NOTE 14 - 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 then 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 ($0.7 million for the period July 1, 1999 to December 31, 2000). Measuring the amount of the allowances requires judgements 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 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 S-25 69 69 the bankruptcy court in the first half of 2001, we will retain our security interest in Mr. Benton's 600,000 shares of our stock and in his stock options, and in a portion of certain proceeds of his Consulting Agreement. Repayment of our loans to Mr. Benton may be achieved through Mr. Benton's liquidation of certain real and personal property assets; a phased liquidation of stock in our company resulting from Mr. Benton's exercise of his stock options; and, if necessary, from the retained interest in the portion of the Consulting Agreement's proceeds. The amount that we eventually realize and the timing of receipt of payments will depend upon the timing and results of the liquidation of Mr. Benton's assets, including Benton Oil and Gas Company stock. Under the terms of the Consulting Agreement, Mr. Benton will be paid consulting fees of $485,000 for 2000, reducing to $322,000 in 2001, $240,000 in 2002, and a declining consulting fee for the remainder of the term which expires December 31, 2006. Mr. Benton will also be entitled to certain additional incentive bonuses with respect to cash receipts we receive in connection with the operations or divestiture of Geoilbent and Arctic Gas. To the extent that Mr. Benton continues to be a consultant to our company, his unvested stock options will continue to vest and for a period of twelve (12) months thereafter. Mr. Benton's consulting services will relate principally to our Russian activities. From February 2000 through December 31, 2000, we paid to Mr. Benton $419,712 under the Consulting Agreement. Also during 1997 and 1996, we made loans to Mr. M.B. Wray, our Vice Chairman and Mr. J. M. Whipkey, our then Chief Financial Officer, each loan bearing interest at 6 percent and collateralized by a security interest in personal real estate. On May 11, 1999, Mr. Wray repaid the balance of principal and interest on his loan and on April 25, 2000, Mr. Whipkey repaid the balance of principal and interest on his loan. In addition, loans and other receivables from other employees (including one former employee) totaled $0.1 million and $0.2 million at December 31, 2000 and 1999, respectively. NOTE 15 - 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) and denominator (shares) of the basic and diluted earnings per share computations were (in thousands, except per share amounts):
AMOUNT INCOME/(LOSS) SHARES PER SHARE ------------ --------- ---------- For the Year Ended December 31, 2000 - ------------------------------------ BASIC EPS Income before extraordinary item available to common stockholders and assumed conversions ....................................... $ 16,528 30,724 $ 0.54 ========= ========= ========= Effect of Dilutive Securities: Stock options and warrants ....................................... - 166 --------- --------- DILUTED EPS Income before extraordinary item available to common stockholders $ 16,528 30,890 $ 0.53 ========= ========= ========= For the Year Ended December 31, 1999 - ------------------------------------ BASIC EPS Loss available to common stockholders ............................ $ (32,284) 29,577 $ (1.09) --------- --------- ========= Effect of Dilutive Securities: Stock options and warrants ....................................... - - --------- --------- DILUTED EPS Loss available to common stockholders and assumed conversions .................................................... $ (32,284) 29,577 $ (1.09) ========= ========= ========= For the Year Ended December 31, 1998 - ------------------------------------ BASIC EPS Loss available to common stockholders ............................ $(183,580) 29,554 $ (6.21) --------- --------- ========= Effect of Dilutive Securities: Stock options and warrants ....................................... - - --------- --------- DILUTED EPS Income available to common stockholders .......................... $(183,580) 29,554 $ (6.21) ========= ========= =========
S-26 70 70 An aggregate of 5.6 million options and warrants were excluded from the earnings per share calculations because their exercise price exceeded the average share price during the year ended December 31, 2000. For the years ended December 31, 1999 and 1998 6.2 million and 3.3 million options and warrants, respectively, were excluded from the earnings per share calculations because they were anti-dilutive. BENTON OIL AND GAS COMPANY AND SUBSIDIARIES QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data is as follows:
QUARTER ENDED ------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- -------- ------------ ----------- (amounts in thousands, except per share data) YEAR ENDED DECEMBER 31, 2000 Revenues ......................................... $ 31,433 $ 32,111 $ 37,972 $ 38,768 Expenses ......................................... (18,647) (22,357) (22,270) (23,806) Non-operating income (expense) ................... (5,248) (5,201) (5,017) (4,622) -------- -------- -------- -------- Income from consolidated companies before income taxes and minority interests ........... 7,538 4,553 10,685 10,340 Income tax expense ............................... 4,636 3,656 5,018 722 -------- -------- -------- -------- Income before minority interests ................. 2,902 897 5,667 9,618 Minority interests ............................... 1,634 1,336 2,007 2,892 -------- -------- -------- -------- Income (loss) from consolidated companies ........ 1,268 (439) 3,660 6,726 Equity in earnings of affiliated companies ....... 1,727 177 2,213 1,196 -------- -------- -------- -------- Income (loss) before extraordinary income ........ 2,995 (262) 5,873 7,922 Extraordinary income on debt repurchase .......... - - 3,095 865 -------- -------- -------- -------- Net income (loss) ................................ $ 2,995 $ (262) $ 8,968 $ 8,787 ======== ======== ======== ======== Net income (loss) per common share: Basic .................................... $ 0.10 $ (0.01) $ 0.29 $ 0.26 Diluted .................................. $ 0.10 $ (0.01) $ 0.29 $ 0.26 QUARTER ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- -------- ------------ ------------ (amounts in thousands, except per share data) YEAR ENDED DECEMBER 31, 1999 Revenues ......................................... $ 16,090 $ 20,351 $ 24,565 $ 28,054 Expenses ......................................... (20,337) (23,318) (32,342) (35,589) Non-operating income (expense) ................... (4,638) (4,571) (4,909) (5,099) -------- -------- -------- -------- Loss from consolidated companies before income taxes and minority interests ........... (8,885) (7,538) (12,686) (12,634) Income tax expense (benefit) ..................... 653 306 1,123 (9,608) -------- -------- -------- -------- Loss before minority interests ................... (9,538) (7,844) (13,809) (3,026) Minority interests ............................... 155 200 177 404 -------- -------- -------- -------- Loss from consolidated companies ................. (9,693) (8,044) (13,986) (3,430) Equity in earnings (losses) of affiliated companies .......................... 1,030 488 (143) 1,494 -------- -------- -------- -------- Net loss ......................................... $ (8,663) $ (7,556) $(14,129) $ (1,936) ======== ======== ======== ======== Net loss per common share: Basic .................................... $ (0.29) $ (0.26) $ (0.48) $ (0.07) Diluted .................................. $ (0.29) $ (0.26) $ (0.48) $ (0.07)
S-27 71 71 SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" ("SFAS 69"), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. TABLE I - TOTAL COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (IN THOUSANDS):
EQUITY CONSOLIDATED COMPANIES AFFILIATES ----------------------------------------------- ---------- UNITED STATES VENEZUELA CHINA AND OTHER SUBTOTAL RUSSIA TOTAL --------- -------- --------- --------- --------- --------- YEAR ENDED DECEMBER 31, 2000 Acquisition costs .................................. $ - $ - $ 170 $ 170 $ - $ 170 Development costs .................................. 47,604 - - 47,604 13,887 61,491 Exploration costs .................................. 94 84 2,470 2,648 4,206 6,854 --------- -------- --------- --------- --------- --------- $ 47,698 $ 84 $ 2,640 $ 50,422 $ 18,093 $ 68,515 ========= ======== ========= ========= ========= ========= YEAR ENDED DECEMBER 31, 1999 Development costs .................................. $ 22,361 $ - $ 104 $ 22,465 $ 6,342 $ 28,807 Exploration costs .................................. 261 8,480 1,761 10,502 1,345 11,847 --------- -------- --------- --------- --------- --------- $ 22,622 $ 8,480 $ 1,865 $ 32,967 $ 7,687 $ 40,654 ========= ======== ========= ========= ========= ========= YEAR ENDED DECEMBER 31, 1998 Development costs .................................. $ 75,928 $ - $ 2,105 $ 78,033 $ 13,276 $ 91,309 Exploration costs .................................. 4,230 4,024 7,853 16,107 3,550 19,657 --------- -------- --------- --------- --------- --------- $ 80,158 $ 4,024 $ 9,958 $ 94,140 $ 16,826 $ 110,966 ========= ======== ========= ========= ========= =========
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES (IN THOUSANDS):
EQUITY CONSOLIDATED COMPANIES AFFILIATES ------------------------------------------------ ----------- UNITED STATES VENEZUELA CHINA AND OTHER SUBTOTAL RUSSIA TOTAL --------- -------- --------- --------- --------- --------- DECEMBER 31, 2000 Proved property costs .............................. $ 426,330 $ 12,879 $ 19,362 $ 458,571 $ 85,086 $ 543,657 Costs excluded from amortization ................... - 16,183 451 16,634 6,536 23,170 Oilfield inventories ............................... 15,343 - - 15,343 2,705 18,048 Less accumulated depletion and impairment .......... (339,542) (12,879) (19,090) (371,511) (27,249) (398,760) --------- -------- --------- --------- --------- --------- $ 102,131 $ 16,183 $ 723 $ 119,037 $ 67,078 $ 186,115 ========= ======== ========= ========= ========= ========= DECEMBER 31, 1999 Proved property costs .............................. $ 378,631 $ 12,870 $ 18,025 $ 409,526 $ 68,526 $ 478,052 Costs excluded from amortization ................... - 16,108 9 16,117 5,004 21,121 Oilfield inventories ............................... 9,806 - - 9,806 2,084 11,890 Less accumulated depletion and impairment .......... (324,211) (12,870) (17,753) (354,834) (24,102) (378,936) --------- -------- --------- --------- --------- --------- $ 64,226 $ 16,108 $ 281 $ 80,615 $ 51,512 $ 132,127 ========= ======== ========= ========= ========= ========= DECEMBER 31, 1998 Proved property costs .............................. $ 371,369 $ - $ 6,083 $ 377,452 $ 61,520 $ 438,972 Costs excluded from amortization ................... - 20,498 10,415 30,913 4,315 35,228 Oilfield inventories ............................... 7,214 - - 7,214 2,080 9,294 Less accumulated depletion and impairment .......... (309,381) - (6,083) (315,464) (20,857) (336,321) --------- -------- --------- --------- --------- --------- $ 69,202 $ 20,498 $ 10,415 $ 100,115 $ 47,058 $ 147,173 ========= ======== ========= ========= ========= =========
S-28 72 72 TABLE III - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES (IN THOUSANDS):
EQUITY CONSOLIDATED COMPANIES AFFILIATES ----------------------------------- ---------- UNITED STATES VENEZUELA AND OTHER SUBTOTAL RUSSIA TOTAL --------- --------- --------- -------- --------- YEAR ENDED DECEMBER 31, 2000 Oil sales ......................................................... $ 139,890 $ 394 $ 140,284 $ 26,091 $ 166,375 Expenses: Operating expenses and taxes other than on income .............. 46,879 731 47,610 10,152 57,762 Depletion ...................................................... 15,331 45 15,376 3,305 18,681 Write-down of oil and gas properties and impairments ........... - 1,346 1,346 - 1,346 Income tax expense ............................................. 20,398 12 20,410 3,275 23,685 --------- -------- --------- -------- --------- Total expenses ................................................ 82,608 2,134 84,742 16,732 101,474 --------- -------- --------- -------- --------- Results of operations from oil and natural gas producing activities $ 57,282 $ (1,740) $ 55,542 $ 9,359 $ 64,901 ========= ======== ========= ======== ========= YEAR ENDED DECEMBER 31, 1999 Oil sales ......................................................... $ 89,060 $ - $ 89,060 $ 11,006 $ 100,066 Expenses: Operating expenses and taxes other than on income .............. 38,841 710 39,551 4,139 43,690 Depletion ...................................................... 14,829 - 14,829 3,325 18,154 Write-down of oil and gas properties and impairments ........... - 25,891 25,891 - 25,891 Income tax expense ............................................. 3,812 638 4,450 436 4,886 --------- -------- --------- -------- --------- Total expenses ............................................. 57,482 27,239 84,721 7,900 92,621 --------- -------- --------- -------- --------- Results of operations from oil and natural gas producing activities $ 31,578 $(27,239) $ 4,339 $ 3,106 $ 7,445 ========= ======== ========= ======== ========= YEAR ENDED DECEMBER 31, 1998 Oil sales ......................................................... $ 82,215 $ (3) $ 82,212 $ 8,059 $ 90,271 Expenses: Operating expenses and taxes other than on income .............. 39,069 1,161 40,230 4,445 44,675 Depletion ...................................................... 31,843 - 31,843 2,474 34,317 Write-down of oil and gas properties and impairments ........... 187,811 6,082 193,893 10,100 203,993 Income tax benefit ............................................. (26,793) - (26,793) - (26,793) --------- -------- --------- -------- --------- Total expenses ............................................. 231,930 7,243 239,173 17,019 256,192 --------- -------- --------- -------- --------- Results of operations from oil and natural gas producing activities $(149,715) $ (7,246) $(156,961) $ (8,960) $(165,921) ========= ======== ========= ======== =========
Geoilbent (34 percent ownership by us) and Arctic Gas (29 percent, 24 percent and 10 percent ownership not subject to certain sale and transfer restrictions at December 31, 2000, 1999 and 1998, respectively), which are accounted for under the equity method, have been included at their respective ownership interests in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, results of operations for oil and natural gas producing activities in Russia reflect the years ended September 30, 2000, 1999 and 1998 for Geoilbent and the years ended September 30, 2000 and 1999 for Arctic Gas. TABLE IV - QUANTITIES OF OIL AND NATURAL GAS RESERVES Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. All Venezuelan reserves are attributable to an operating service agreement between Benton-Vinccler and PDVSA, under which all mineral rights are owned by the government of Venezuela. The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be Proved Reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. S-29 73 73 Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well. Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates. Proved Reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. S-30 74 74 The evaluations of the oil and natural gas reserves as of December 31, 2000 were prepared by Ryder-Scott, independent petroleum engineers. The evaluations of the oil and natural gas reserves as of December 31, 1999, 1998 and 1997 were audited by Huddleston & Co., Inc., independent petroleum engineers.
EQUITY CONSOLIDATED COMPANIES AFFILIATES ---------------------------------------------------- ---------- MINORITY INTEREST UNITED IN NET STATES VENEZUELA VENEZUELA TOTAL RUSSIA TOTAL ------- --------- --------- -------- -------- -------- PROVED RESERVES-CRUDE OIL, CONDENSATE, AND NATURAL GAS LIQUIDS (MBBLS) YEAR ENDED DECEMBER 31, 2000 Proved reserves beginning of the year ......... - 134,961 (26,992) 107,969 40,129 148,098 Revisions of previous estimates ............. - (8,826) 1,765 (7,061) (2,811) (9,872) Purchases of reserves in place .............. 15 - - 15 - 15 Extensions, discoveries and improved recovery - 6,268 (1,254) 5,014 12,610 17,624 Production .................................. (7) (9,364) 1,873 (7,498) (1,493) (8,991) Sales of reserves in place .................. (8) - - (8) - (8) ------- -------- ------- -------- -------- -------- Proved reserves end of year ................... - 123,039 (24,608) 98,431 48,435 146,866 ======= ======== ======= ======== ======== ======== YEAR ENDED DECEMBER 31, 1999 Proved reserves beginning of the year ......... - 137,835 (27,567) 110,268 31,053 141,321 Revisions of previous estimates ............. - (7,488) 1,498 (5,990) (531) (6,521) Extensions, discoveries and improved recovery - 14,281 (2,856) 11,425 11,058 22,483 Production .................................. - (9,667) 1,933 (7,734) (1,451) (9,185) ------- -------- ------- -------- -------- -------- Proved reserves end of year ................... - 134,961 (26,992) 107,969 40,129 148,098 ======= ======== ======= ======== ======== ======== YEAR ENDED DECEMBER 31, 1998 Proved reserves beginning of the year ......... - 94,671 (18,934) 75,737 26,113 101,850 Revisions of previous estimates ............. - 25,119 (5,024) 20,095 (2,283) 17,812 Extensions, discoveries and improved recovery - 30,217 (6,043) 24,174 8,147 32,321 Production .................................. - (12,172) 2,434 (9,738) (924) (10,662) ------- -------- ------- -------- -------- -------- Proved reserves end of year ................... - 137,835 (27,567) 110,268 31,053 141,321 ======= ======== ======= ======== ======== ======== PROVED DEVELOPED RESERVES AT: December 31, 2000 ............................. - 67,217 (13,443) 53,774 17,238 71,012 December 31, 1999 ............................. - 67,119 (13,423) 53,695 15,120 68,815 December 31, 1998 ............................. - 75,636 (15,127) 60,509 9,745 70,254 December 31, 1997 ............................. - 68,868 (13,774) 55,094 5,443 60,537 PROVED RESERVES-NATURL GAS (MMCF) YEAR ENDED DECEMBER 31, 2000 Proved reserves beginning of the year ......... - - - - - - Revisions of previous estimates ............. - - - - - - Purchases of reserves in place .............. - - - - - - Extensions, discoveries and improved recovery 1,071 - - 1,071 152,496 153,567 Production .................................. (43) - - (43) - (43) Sales of reserves in place .................. (1,028) - - (1,028) - (1,028) ------- -------- ------- -------- -------- -------- Proved reserves end of the year ............... - - - - 152,496 152,496 ======= ======== ======= ======== ======== ======== PROVED DEVELOPED RESERVES AT: December 31, 2000 ............................. - - - - 17,801 17,801 December 31, 1999 ............................. - - - - - -
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND NATURAL GAS RESERVE QUANTITIES The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions. Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate. S-31 75 75 Geoilbent received a waiver from the export tariff assessed on all oil produced in and exported from Russia for 1995. In July 1996, such oil export tariffs were terminated in conjunction with a loan agreement with the International Monetary Fund, although a new oil export tariff of 15 Euros per ton ($1.97 per Bbl) was introduced in 1999 and increased to 34 Euros per ton (approximately $3.80 per Bbl) in 2000. Excise, pipeline and other taxes continue to be levied on all oil producers and certain exporters. Although the Russian regulatory environment has become less volatile, we are unable to predict the impact of taxes, duties and other burdens for the future.
EQUITY CONSOLIDATED COMPANIES AFFILIATES ----------------------------------------- ---------- MINORITY INTEREST IN VENEZUELA VENEZUELA NET TOTAL RUSSIA TOTAL ----------- ------------ ----------- ----------- ----------- (amounts in thousands) DECEMBER 31, 2000 Future cash inflow ................................ $ 1,505,870 $(301,174) $ 1,204,696 $ 1,273,327 $ 2,478,023 Future production costs ........................... (618,870) 123,774 (495,096) (811,678) (1,306,774) Future development costs .......................... (166,039) 33,208 (132,831) (70,620) (203,451) ----------- --------- ----------- ----------- ----------- Future net revenue before income taxes ............ 720,961 (144,192) 576,769 391,029 967,798 10% annual discount for estimated timing of cash flows .................................. (260,381) 52,076 (208,305) (176,352) (384,657) ----------- --------- ----------- ----------- ----------- Discounted future net cash flows before income taxes ................................... 460,580 (92,116) 368,464 214,677 583,141 Future income taxes, discounted at 10% per annum ...................................... (104,894) 20,979 (83,915) (43,072) (126,987) ----------- --------- ----------- ----------- ----------- Standardized measure of discounted future net cash flows ................................. $ 355,686 $ (71,137) $ 284,549 $ 171,605 $ 456,154 =========== ========= =========== =========== =========== DECEMBER 31, 1999 Future cash inflow ................................ $ 1,727,228 $(345,446) $ 1,381,782 $ 566,201 $ 1,947,983 Future production costs ........................... (543,976) 108,795 (435,181) (150,370) (585,551) Future development costs .......................... (144,639) 28,928 (115,711) (38,210) (153,921) ----------- --------- ----------- ----------- ----------- Future net revenue before income taxes ............ 1,038,613 (207,723) 830,890 377,621 1,208,511 10% annual discount for estimated timing of cash flows .................................. (386,930) 77,386 (309,544) (154,032) (463,576) ----------- --------- ----------- ----------- ----------- Discounted future net cash flows before income taxes ................................... 651,683 (130,337) 521,346 223,589 744,935 Future income taxes, discounted at 10% per annum ...................................... (175,602) 35,121 (140,481) (47,676) (188,157) ----------- --------- ----------- ----------- ----------- Standardized measure of discounted future net cash flows ................................. $ 476,081 $ (95,216) $ 380,865 $ 175,913 $ 556,778 =========== ========= =========== =========== =========== DECEMBER 31, 1998 Future cash inflow ................................ $ 778,765 $(155,753) $ 623,012 $ 183,524 $ 806,536 Future production costs ........................... (527,856) 105,571 (422,285) (70,953) (493,238) Future development costs .......................... (147,806) 29,561 (118,245) (25,048) (143,293) ----------- --------- ----------- ----------- ----------- Future net revenue before income taxes ............ 103,103 (20,621) 82,482 87,523 170,005 10% annual discount for estimated timing of cash flows .................................. (40,648) 8,130 (32,518) (37,977) (70,495) ----------- --------- ----------- ----------- ----------- Discounted future net cash flows before income taxes ................................... 62,455 (12,491) 49,964 49,546 99,510 Future income taxes, discounted at 10% per annum ...................................... - - - (6,298) (6,298) ----------- --------- ----------- ----------- ----------- Standardized measure of discounted future net cash flows ................................. $ 62,455 $ (12,491) $ 49,964 $ 43,248 $ 93,212 =========== ========= =========== =========== ===========
S-32 76 76 TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
CONSOLIDATED COMPANIES EQUITY AFFILIATES ---------------------------- --------------------------------- 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- (amounts in thousands) Present Value at January 1 ....................... $ 380,865 $ 49,964 $ 233,176 $ 175,913 $ 43,248 $ 63,433 Sales of oil and natural gas, net of related costs (58,913) (40,303) (34,513) (20,977) (3,238) (3,614) Revisions to estimates of proved reserves Net changes in prices, development and production costs ............................ (124,402) 552,614 (295,131) (72,740) 120,742 (43,072) Quantities ..................................... (26,494) (26,671) 11,809 (19,685) (2,858) (3,134) Sales of reserves in place Extensions, discoveries and improved recovery, net of future costs ............................ 16,429 65,184 22,893 73,542 54,326 18,132 Accretion of discount ............................ 52,135 4,996 29,123 22,359 4,955 7,770 Net change in income taxes ....................... 56,567 (140,481) 58,054 4,604 (41,378) 7,965 Development costs incurred ....................... 36,210 28,558 37,832 8,475 4,370 8,311 Changes in timing and other ...................... (47,848) (112,996) (13,279) 114 (4,254) (12,543) --------- --------- --------- --------- --------- -------- Present Value at December 31 ..................... $ 284,549 $ 380,865 $ 49,964 $ 171,605 $ 175,913 $ 43,248 ========= ========= ========= ========= ========= ======== TOTAL ----- 2000 1999 1998 ---- ---- ---- Present Value at January 1 ....................... $ 556,778 $ 93,212 $ 296,609 Sales of oil and natural gas, net of related costs (79,890) (43,541) (38,127) Revisions to estimates of proved reserves Net changes in prices, development and production costs ............................ (197,142) 673,356 (338,203) Quantities ..................................... (46,179) (29,529) 8,675 Sales of reserves in place Extensions, discoveries and improved recovery, net of future costs ............................ 89,971 119,510 41,025 Accretion of discount ............................ 74,494 9,951 36,893 Net change in income taxes ....................... 61,171 (181,859) 66,019 Development costs incurred ....................... 44,685 32,928 46,143 Changes in timing and other ...................... (47,734) (117,250) (25,822) --------- --------- --------- Present Value at December 31 ..................... $ 456,154 $ 556,778 $ 93,212 ========= ========= =========
S-33 77 77 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Carpinteria, State of California, on the 30th day of March, 2001. BENTON OIL AND GAS COMPANY -------------------------- (Registrant) Date: March 30, 2001 By:/s/Peter J. Hill ------------------- -------------------------- Peter J. Hill Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 30th day of March, 2001, on behalf of the Registrant in the capacities indicated:
Signature Title --------- ----- /s/Peter J. Hill Director, President and Chief Executive Officer ----------------------------------- Peter J. Hill /s/Steven W. Tholen Senior Vice President, Chief Financial ----------------------------------- Officer and Treasurer Steven W. Tholen (Principal Financial Officer) /s/Chris C. Hickok Vice President-Controller ----------------------------------- Chris C. Hickok (Principal Accounting Officer) /s/Michael B. Wray Chairman of the Board and Director ----------------------------------- Michael B. Wray /s/Stephen D. Chesebro' Director ----------------------------------- Stephen D. Chesebro' /s/John U. Clarke Director ----------------------------------- John U. Clarke /s/Byron A. Dunn Director ----------------------------------- Byron A. Dunn /s/H.H. Hardee Director ---------------------------------- H.H. Hardee /s/Patrick M. Murray Director ----------------------------------- Patrick M. Murray
78 78
SCHEDULE II BENTON OIL AND GAS COMPANY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS (IN THOUSANDS) ADDITIONS -------------------------- BALANCE AT CHARGED TO DEDUCTIONS BALANCE AT BEGINNING OF CHARGED TO OTHER FROM END OF YEAR INCOME ACCOUNTS RESERVES YEAR ------------ ---------- ---------- --------- ---------- AT DECEMBER 31, 2000 Amounts deducted from applicable assets Accounts receivable $ 6,187 $ 331 - - $ 6,518 Deferred tax asset 51,913 2,446 - 152 54,207 Investment at cost 1,350 - - - 1,350 AT DECEMBER 31, 1999 Amounts deducted from applicable assets Accounts receivable $ 3,236 $ 858 2,093 - $ 6,187 Deferred tax asset 45,962 14,541 - 8,590 51,913 Investment at cost - 1,350 - - 1,350 Reserves included in stockholders' equity Allowance for employee note secured by Benton Oil and Gas Company stock 2,093 - (2,093) - - AT DECEMBER 31, 1998 Amounts deducted from applicable assets Accounts receivable $ 367 $ 2,869 - - $ 3,236 Deferred tax asset 13,841 32,121 - - 45,962 Reserves included in stockholders' equity Allowance for employee note secured by Benton Oil and Gas Company stock - 2,093 - - 2,093
EX-3.3 2 l86922aex3-3.txt EXHIBIT 3.3 1 EXHIBIT 3.3 RESTATED JANUARY 5, 2001 BYLAWS OF BENTON OIL AND GAS COMPANY ARTICLE 1. SHAREHOLDERS 1.1. ANNUAL MEETING. The annual meeting of the shareholders shall be held on the second Tuesday in the month of May in each year at the hour of 10 a.m., for the purpose of electing directors and transacting such other business as may come before the meeting. If the day fixed for the annual meeting is a legal holiday, the meeting shall be held on the next succeeding business day. 1.2. FAILURE TO HOLD ANNUAL MEETING. If the annual meeting is not held at the designated time, the directors shall cause the meeting to be held as soon as thereafter as convenient. If there is a failure to hold an annual meeting for a period of 30 days after the date designated, any shareholder or director may apply to the Court of Chancery to summarily order a meeting held. 1.3. SPECIAL MEETINGS. Special meetings of the shareholders may be called by the President, by the Board of Directors or by the holder of not less than ten percent of the stock entitled to vote in the election of directors. 1.4. PLACE OF MEETINGS. Meetings of the shareholders shall be held at the principal business office of the corporation or at such other place as may be determined by the Board of Directors. 1.5. NOTICE OF MEETINGS. Written or printed notice stating the place, day and hour of the meeting and, in case of a special meeting, the purpose or purposes for which the meeting is called, shall be mailed to each shareholder entitled to vote at the meeting at the shareholder's address as it appears on the stock transfer records of the corporation, with postage thereon prepaid, not less than 10 nor more than 60 days before the date of the meeting, by or at the direction of the President, the Secretary or the Board of Directors. 1.6. WAIVER OF NOTICE. Whenever any notice is required to be given to any shareholder of the corporation, a waiver thereof in writing, signed by the person or persons entitled to such 2 notice, whether before or after the time stated therein, shall be deemed equivalent to the giving of such notice. The attendance of a shareholder at a meeting shall constitute a waiver of notice of such meeting, except where a shareholder attends a meeting for the express purpose of objecting to the transaction of any business because the meeting is not lawfully called or convened. 1.7. FIXING OF RECORD DATE. (a) In order that the corporation may determine the shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or to express consent of corporation action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the Board of Directors may fix, in advance, a record date, which shall not be more than 60 nor less than 10 days before the date of such meeting, nor more than 60 days prior to any other action. (b) If no record date is fixed: (1) The record date for determining shareholders entitled to notice of or to vote at a meeting of shareholders shall be at the close of business on the day next preceding the day on which notice is given, or, if notice is waived, at the close of business on the day next preceding the day on which the meeting is held; (2) The record date for determining shareholders entitled to express consent to corporate action in writing without a meeting, when no prior action by the Board of Directors is necessary, shall be the day on which the first written consent is expressed; (3) The record date for determining shareholders for any other purpose shall be at the close of business on the day on which the Board of Directors adopts the resolution relating thereto. (c) A determination of shareholders of record entitled to notice of or to vote at a meeting of shareholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjournment meeting. 1.8. VOTING RECORDS. (a) The officer who has charge of the stock ledger of a corporation shall make, at least 10 days before every meeting of shareholders, a complete list of the shareholders entitled to vote at the meeting, arranged in alphabetical order, and showing the address of each shareholder and the number of shares registered in the name of each shareholder. Such list shall be open to the examination of any shareholder, for any purpose germane to the meeting, during ordinary business hours, for a period of at least 10 days prior to the meeting, either at a place within the city where the meeting is to be held, which place shall be specified in the notice of the meeting, or, if not so specified, at the place where the meeting is to be held. The list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any shareholder who is present. 2 3 (b) Upon the willful neglect or refusal of the directors to produce such a list at any meeting for the election of directors they shall be ineligible for election to any office at such meeting. (c) The stock ledger shall be the only evidence as to who are the shareholders entitled to examine the stock ledger, the shareholder list or the books of the corporation, or to vote in person or by proxy at any meeting of shareholders. 1.9. QUORUM. A majority of the outstanding shares of the corporation entitled to vote, represented in person or by proxy, shall constitute a quorum at a meeting of shareholders. If a quorum is present at a meeting, a majority may adjourn the meeting from time to time to a different time and place without further notice if the time and place thereof are announced at the meeting at which the adjournment is taken. At such adjourned meeting at which a quorum is present, any business may be transacted which might have been transacted at the meeting as originally called. If the adjournment is for more than 30 days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each shareholder of record entitled to vote at the meeting. The shareholders present at a duly organized meeting may continue to transact business until adjournment, notwithstanding the withdrawal of enough shareholders to leave less than a quorum. 1.10. MAJORITY VOTE; ACTION WITHOUT A MEETING. The vote of the holders of a majority of the shares present and entitled to vote any duly organized meeting shall decide any question unless the vote of a greater number shall be required by law, the Certificate of Incorporation or these Bylaws. Any action which the shareholders could take at a meeting may be taken without a meeting if a consent in writing setting forth the action so taken is signed by the holders of outstanding stock having not less than the minimum number of shares that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Prompt notice of the taking of the corporate action without a meeting by less than unanimous written consent shall be given to those shareholders who have not consented in writing and the consent shall be filed with the minutes of the corporation. 1.11. PROXIES. At all meetings of shareholders, a shareholder may vote by proxy executed in writing by the shareholder or by a duly authorized attorney in fact. The proxy shall be filed with the Secretary of the corporation before or at the time of the meeting. No proxy shall be valid after three years from the date of its execution, unless otherwise provided in the proxy. 1.12. VOTING OF SHARES BY CERTAIN HOLDERS. (a) Persons holding stock in a fiduciary capacity shall be entitled to vote the shares so held. Persons whose stock is pledged shall be entitled to vote, unless in the transfer by the pledgor on the books of the corporation he or she has expressly empowered the pledgee to vote thereon, in which case only the pledgee, or his or her proxy, may represent such stock and vote thereon. 3 4 (b) If shares or other securities having voting power stand of record in the names of two or more persons, or if two or more persons have the same fiduciary relationship respecting the same shares, unless the Secretary is given written notice to the contrary and is furnished with a copy of the instrument or order appointing them or creating the relationship wherein it is so provided, their acts with respect to voting shall have the following effect: (1) If only one votes, the act of such person binds all; (2) If more than one votes, the act of the majority so voting binds all; (3) If more than one votes and if the vote is evenly split on any particular matter, each faction may vote the securities in question proportionally, or any person voting the shares, or a beneficiary, if any, may apply to the Court of Chancery or such other court as may have jurisdiction to appoint an additional person to act with the person so voting the shares, which shall then be voted as determined by a majority of such persons and the person appointed by the court. If the instrument so filed shows that any such tenancy is held in unequal interests, a majority or even split for the purpose of this subsection shall be a majority or even split in interest. ARTICLE 2. BOARD OF DIRECTORS 2.1. GENERAL POWERS. The business and affairs of the corporation shall be managed by its Board of Directors. 2.2. NUMBER, TENURE AND QUALIFICATION. The number of Directors of the Corporation shall be seven. The directors shall hold office until the next annual meeting of shareholders and until their successors shall have been elected and qualified. The number of directors permitted under the Bylaws may be increased or decreased from time to time by amendment to the Bylaws. Directors need not be residents of the State of Delaware or shareholders of the corporation. 2.3. REGULAR MEETINGS. A regular meeting of the Board of Directors shall be held without other notice than this Bylaw immediately after, and at the same place as, the annual meeting of shareholders. The Board of Directors may provide, by resolution, the time and place, either within or without the State of Delaware, for the holding of additional regular meetings without other notice than the resolution. 2.4. SPECIAL MEETINGS. Special meetings of the Board of Directors may be called by or at the request of the President or by one-third of the directors. The person or persons authorized to call special meetings of the Board of Directors may fix any place, either within or without the State of Delaware, as the place for holding any special meeting of the Board of Directors called by them. 4 5 2.5. NOTICE. Written notice of any special meeting of the Board of Directors shall be given at least two days prior to the meeting by personal delivery, by mail or by telegram. Notice with respect to telephonic board meetings shall be given at least 24 hours prior to the meeting by personal delivery, telephone, mail or telefax. If mailed, notice shall be deemed to be given when deposited in the United States mails addressed to the director at the director's business address, with postage thereon prepaid. If by telegram, notice shall be deemed to be given when the telegram is delivered to the telegraph company. The attendance of a director at a meeting shall constitute a waiver of notice of such meeting, except where the director attends a meeting for the express purpose of objecting to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Board of Directors need be specified in the notice or waiver of notice of such meeting. 2.6. WAIVER OF NOTICE. Whenever any notice is required to be given to any director of the corporation, waiver thereof in writing, signed by the person or persons entitled to such notice, whether before or after the time stated therein, shall be deemed equivalent to the giving of such notice. 2.7. QUORUM; MAJORITY VOTE. A majority of the number of directors fixed by Section 2.2 of this Article 2 shall constitute a quorum for the transaction of business at any meeting of the Board of Directors. The act of the majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors, unless a different number is provided by law, the Certificate of Incorporation or these Bylaws. 2.8. MEETING BY TELEPHONE CONFERENCE; CONSENT IN LIEU OF MEETING. (a) Members of the Board of Directors may hold a board meeting by conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other. Participation in such a meeting shall constitute presence in person at the meeting. (b) Any action which is required or permitted to be taken by the directors at a meeting may be taken without a meeting if a consent in writing setting forth the action so taken is signed by all of the directors entitled to vote on the matter. Such consent, which shall have the same effect as a unanimous vote of the directors, shall be filed with the minutes of the corporation. 2.9. VACANCIES. Except as otherwise provided by law, vacancies and newly created directorships resulting from any increase in the authorized number of directors may be filled by affirmative vote of a majority of the remaining directors though less than a quorum of the Board of Directors, or by a sole remaining director. Any such directorship not so filled by the directors shall be filled by election at the next annual meeting of shareholders or at a special meeting of shareholders called for that purpose. A director elected to fill a vacancy shall be elected to serve until the next annual meeting of shareholders and until a successor shall be elected and qualified. 5 6 2.10. COMPENSATION. By resolution of the Board of Directors, the directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors, and may be paid a fixed sum for attendance at each meeting of the Board of Directors or a stated salary as director. No such payment shall preclude any director from serving the corporation in any other capacity and receiving compensation therefor. 2.11. PRESUMPTION OF ASSENT. A director of the corporation who is present at a meeting of the Board of Directors at which action on any corporate matter is taken shall be presumed to have assented to the action taken unless the director's dissent to the action is entered in the minutes of the meeting or unless a written dissent to the action is filed with the person acting as the secretary of the meeting before the adjournment thereof or forwarded by certified or registered mail to the Secretary of the corporation immediately after the adjournment of the meeting. The right to dissent shall not apply to a director who voted in favor of the action. 2.12. TRANSACTIONS WITH DIRECTORS. (a) Any contract or other transaction or determination between the corporation and one or more of its directors, or between the corporation and another party in which one or more of its directors are interested, shall be valid notwithstanding the relationship or interest or the presence or participation of such director or directors in a meeting of the Board of Directors or a committee thereof which acts upon or in reference to such contract, transaction or determination, if: (1) The material facts as to such relationship or interest and as to the contract or transaction are disclosed or are known to the Board of Directors or committee and it authorizes the contract or transaction by the affirmative vote of a majority of the disinterested directors, even though the disinterested directors are less than a quorum; or (2) The material facts as to such relationship or interest and as to the contract or transaction are disclosed or are known to the shareholders entitled to vote, and the contract or transaction is specifically approved in good faith by vote of the shareholders; or (3) The contract or transaction is fair as to the corporation as of the time it is authorized, approved or ratified, by the Board of Directors, a committee thereof or the shareholders. (b) None of the provisions of this section shall invalidate any contract, transaction or determination which would otherwise be valid under applicable law. 2.13. REMOVAL. All or any number of the directors may be removed, with or without cause, by a vote of the holders of a majority of the shares then entitled to vote at an election of directors. 2.14. RESIGNATION. Any director may resign by delivering his or her resignation, in writing, to the corporation at its principal office or to the President or Secretary. Such 6 7 resignation shall be effective on receipt unless it is specified to be effective at some other time or upon the happening of some other event. ARTICLE 3. COMMITTEES 3.1. DESIGNATION. The Board of Directors may designate from among its members an executive committee and/or one or more other committees, each consisting of one or more directors. The designation of a committee, and the delegation of authority to it, shall not operate to relieve the Board of Directors, or any member thereof, of any responsibility imposed by law. No member of any committee shall continue to be a member thereof after ceasing to be a director of the corporation. The Board of Directors shall have the power at any time to increase or decrease the number of members of any committee, to fill vacancies thereon, to change any member thereof and to change the functions or terminate the existence thereof. 3.2. POWERS. Any such committee, to the extent provided by resolution of the Board of Directors, shall have and may exercise all the powers and authority of the Board of Directors in the management of the business and affairs of the corporation, and may authorize the seal of the corporation to be affixed to all papers which may require it; but no such committee shall have the power or authority in reference to amending the Certificate of Incorporation; adopting an agreement of merger or consolidation; recommending to the shareholders the sale, lease or exchange of all or substantially all of the corporation's property and assets; recommending to the shareholders a dissolution of the corporation or a revocation of a dissolution; or amending the Bylaws of the Corporation; and, unless the resolution expressly so provides, no such committee shall have the power or authority to declare a dividend, to authorize the issuance of stock or to adopt a certificate of ownership and merger with respect to the merger into the corporation of a subsidiary of which at least 90 percent of the outstanding shares of each class are owned by the corporation. 3.3. PROCEDURES; MEETINGS; QUORUM. (a) The Board of Directors shall appoint a chairman from among the members of the committee and shall appoint a secretary who may, but need not, be a member of the committee. The chairman shall preside at all committee meetings and the secretary of the committee shall keep a record of its acts and proceedings. (b) Regular meetings of a committee, of which no notice shall be necessary, shall be held on such days and at such places as shall be fixed by resolution adopted by the committee. Special meetings of a committee shall be called at the request of the President or of any member of the committee, and shall be held upon such notice as is required by these Bylaws for special meetings of the Board of Directors, provided that notice by word of mouth or telephone shall be sufficient if received in the city where the meeting is to be held not later than the day immediately preceding the day of the meeting. A waiver of notice of a meeting, signed by the 7 8 person or persons entitled to such notice, whether before or after the event stated therein, shall be deemed equivalent to the giving of such notice. (c) Attendance of any member of a committee at a meeting shall constitute a waiver of notice of the meeting. A majority of a committee, from time to time, shall be necessary to constitute a quorum for the transaction of any business, and the act of a majority of the members present at a meeting at which a quorum is present shall be the act of the committee. Members of a committee may hold a meeting of such committee by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in such a meeting shall constitute presence in person at the meeting. (d) Any action which may be taken at a meeting of a committee may be taken without a meeting if a consent in writing setting forth the actions so taken shall be signed by all members of the committee entitled to vote with respect to the subject matter thereof. The consent shall have the same effect as a unanimous vote of the committee. (e) The Board of Directors may vote to the members of any committee a reasonable fee as compensation for attendance at meetings of the committee. ARTICLE 4. OFFICERS 4.1. NUMBER. The officers of the corporation shall be a Chairman of the Board, a President and a Secretary. Such other officers and assistant officers as may be deemed necessary may be elected or appointed by the Board of Directors and shall have such powers and duties as may be prescribed by the Board of Directors. Any two or more offices may be held by the same person. 4.2. ELECTION AND TERM OF OFFICE. The officers of the corporation shall be elected annually by the Board of Directors at the first meeting of the Board of Directors held after the annual meeting of the shareholders. If the election of officers shall not be held at the meeting, it shall be held as soon thereafter as is convenient. Each officer shall hold office until a successor shall have been duly elected and shall have qualified or until the officer's death, resignation or removal in the manner hereinafter provided. 4.3. REMOVAL. Any officer or agent elected or appointed by the Board of Directors may be removed by the Board of Directors whenever in its judgment the best interests of the corporation would be served thereby. 4.4. VACANCIES. A vacancy in any office because of death, resignation, removal, disqualification or otherwise may be filled by the Board of Directors for the unexpired portion of the term. 8 9 4.5. CHIEF EXECUTIVE OFFICER ("CEO"). The CEO shall be the chief executive officer of the corporation and shall be in general charge of its business and affairs, subject to the control of the Board of Directors. The CEO shall preside at all meetings of the shareholders and, in the absence of a Chairman of the Board, at all meetings of directors. The CEO may execute on behalf of the corporation all contracts, agreements, stock certificates and other instruments. The CEO shall from time to time report to the Board of Directors all matters within the CEO's knowledge affecting the corporation which should be brought to the attention of the Board. The CEO shall vote all shares of stock in other corporations owned by the corporation, and shall be empowered to execute proxies, waivers of notice, consents and other instruments in the name of the corporation with respect to such stock. The CEO shall perform such other duties as may be required by the Board of Directors. 4.6. PRESIDENT. The President shall perform such duties as determined by the Board of Directors or the CEO and shall be subject to the control of the Board of Directors. Generally, in the absence of the CEO, the President shall preside at all meetings of stockholders and at all meetings of directors. The President shall execute any and all agreements and instruments required by the corporation and shall from time to time report to the CEO and the President on all information about the corporation that he becomes aware of or is responsible for. The President shall perform such other duties as may be required by the CEO and the Board of Directors. 4.7. SECRETARY. The Secretary shall keep the minutes of all meetings of the directors and shareholders, and shall have custody of the minute books and other records pertaining to the corporate business. The Secretary shall countersign all stock certificates and other instruments requiring the seal of the corporation and shall perform such other duties as may be required by the Board of Directors. 4.8. CHAIRMAN OF THE BOARD. The Chairman of the Board of Directors shall preside at all meetings of the Board of Directors and shall perform such other duties as may be prescribed from time to time by the Board of Directors. 4.9. VICE PRESIDENTS. In the absence of the President or in the event of the President's death or inability or refusal to act, the Vice President (or, in the event there be more than one Vice President, the Vice Presidents in the order designated at the time of their election, or in the absence of any designation, then in the order of their election) shall perform the duties of the President and, when so acting, shall have all the powers of and be subject to all the restrictions upon the President. Any Vice President shall perform such other duties assigned by the President or by the Board of Directors. 4.10. TREASURER. The Treasurer shall be the chief financial and accounting officer of the corporation. The Treasurer shall keep correct and complete records of accounts showing the financial condition of the corporation. The Treasurer shall be legal custodian of all moneys, notes, securities and other valuables that may come into the possession of the corporation. The Treasurer shall deposit all funds of the corporation that come into the Treasurer's hands in depositories that the Board of Directors may designate. The Treasurer shall pay the funds out 9 10 only on the check of the corporation signed in the manner authorized by the Board of Directors. The Treasurer shall perform such other duties as assigned by the Board of Directors may require. 4.11. SALARIES. The salaries of the officers shall be fixed from time to time by the Board of Directors and no officer shall be prevented from receiving such salary because the officer is also a director of the corporation. ARTICLE 5. 5.1. The Corporation shall indemnify to the fullest extent then permitted by the law any person who is made, or threatened to be made, a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative, investigative or otherwise (including an action, suit or proceeding by or in the right of the Corporation) by reason of the fact that the person is or was a director or officer of the Corporation, or serves or served at the request of the Corporation as a director or officer of another corporation, partnership, joint venture, trust or other enterprise against all expenses (including attorneys' fees), judgments, fines and amounts paid in settlement, actually and reasonably incurred in connection therewith. Expenses incurred by an officer or director in defending a civil or criminal action, suit or proceeding shall be paid by the Corporation in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of such director or officer to repay such amount if it shall ultimately be determined that he or she is not entitled to be indemnified by the Corporation as authorized in this Article. The indemnification provided hereby shall not be deemed exclusive of any other rights to which those indemnified may be entitled under any statute, Bylaw, agreement, vote of shareholders or directors or otherwise, both as to action in any official capacity and as to action in another capacity while holding office, and shall continue as to a person who has ceased to be a director or officer and shall inure to the benefit of the heirs, executors and administrators of such person. Any person other than a director or officer who is or was an employee or agent of the Corporation, or fiduciary within the meaning of the Employee Retirement Income Security Act of 1974 with respect to any employee benefit plans of the Corporation, or is or was serving at the request of the Corporation as an employee or agent of another corporation, partnership, joint venture, trust or other enterprise may be indemnified to such extent as the board of directors in its discretion at any time or from time to time may authorize. 5.2. No director of the Corporation shall be personally liable to the Corporation or its stockholders for monetary damages for breach of fiduciary duty as a director; provided that the liability of a director shall not be eliminated (i) for any breach of the director's duty of loyalty to the Corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the Delaware General Corporation Law or (iv) for any transaction from which the director derived an improper personal benefit. 10 11 ARTICLE 6. CERTIFICATE FOR SHARES AND THEIR TRANSFER 6.1. CERTIFICATES FOR SHARES. (a) Certificates representing shares of the corporation shall be in such form as shall be determined by the Board of Directors. Such certificates shall be signed by the President or a Vice President and by the Secretary or an Assistant Secretary and may be sealed with the seal of the corporation or a facsimile thereof. All certificates for shares shall be consecutively numbered or otherwise identified. (b) The name and address of the person to whom the shares represented by each certificate are issued, with the number of shares and date of issue, shall be entered on the stock transfer books of the corporation. All certificates surrendered to the corporation for transfer shall be cancelled and no new certificate shall be issued until the former certificate for a like number of shares shall have been surrendered and cancelled, except that in case of a lost, destroyed or mutilated certificate a new one may be issued therefor upon such terms and indemnity to the corporation as the Board of Directors may prescribe. 6.2. TRANSFER OF SHARES. Transfer of shares of the corporation shall be made only on the stock transfer books of the corporation by the holder of record thereof or by the holder's legal representative, who shall furnish proper evidence of authority to transfer, or by the holder's attorney thereunto authorized by power of attorney duly executed and filed with the Secretary of the corporation. The person in whose name shares stand on the books of the corporation shall be deemed by the corporation to be the owner thereof for all purposes. 6.3. TRANSFER AGENT AND REGISTRAR. The Board of Directors may from time to time appoint one or more transfer agents and one or more registrars for the shares of the corporation, with such powers and duties as the Board of Directors shall determine by resolution. The signatures of the President or Vice President and the Secretary or Assistant Secretary upon a certificate may be facsimiles if the certificate is manually signed on behalf of such officers by a transfer agent or a registrar other than the corporation itself. 6.4. OFFICER CEASING TO ACT. In case any officer who has signed or whose facsimile signature has been placed upon a stock certificate shall have ceased to be such officer before such certificate is issued, it may be issued by the corporation with the same effect as if the signer were such officer at the date of its issuance. 6.5. FRACTIONAL SHARES. The corporation shall not issue certificates for fractional shares. 11 12 ARTICLE 7. CONTRACTS, LOANS, CHECKS AND OTHER INSTRUMENTS 7.1. CONTRACTS. The Board of Directors may authorize any officer or officers and agent or agents to enter into any contract or execute and deliver any instrument in the name of and on behalf of the corporation, and such authority may be general or confined to specific instances. 7.2. LOANS. No loans shall be contracted on behalf of the corporation and no evidence of indebtedness shall be issued in its name unless authorized by a resolution of the Board of Directors. Such authority may be general or confined to specific instances. 7.3. CHECKS, DRAFTS, ETC. All checks, drafts or other orders for the payment of money and notes or other evidences of indebtedness issued in the name of the corporation shall be signed by such officer or officers and agent or agents of the corporation and in such manner as shall from time to time be determined by resolution of the Board of Directors. ARTICLE 8. SEAL 8.1. SEAL. The seal of the corporation shall be circular in form and shall have inscribed thereon the name of the corporation and the state of incorporation and the words "Corporate Seal." 8.2. SEVERABILITY. Any determination that any provision of these Bylaws is for any reason inapplicable, invalid, illegal or otherwise ineffective shall not affect or invalidate any other provision of these Bylaws. 8.3. EVIDENCE OF AUTHORITY. A certificate by the Secretary or an Assistant Secretary as to any action taken by the shareholders, directors, any committee or any officer or representative of the corporation shall as to all persons who rely on the certificate in good faith be conclusive evidence of such action. ARTICLE 9. AMENDMENTS These Bylaws may be altered, amended or repealed and new Bylaws may be adopted by the Board of Directors or by the shareholders at any regular or special meeting. 12 EX-10.21 3 l86922aex10-21.txt EXHIBIT 10.21 1 EXHIBIT 10.21 BENTON OIL AND GAS COMPANY 1999 STOCK OPTION PLAN 1. PURPOSE OF THE PLAN The 1999 Stock Option Plan (the "Plan") is intended to provide additional incentive to certain valued and trusted directors, employees and consultants of Benton Oil and Gas Company, a Delaware corporation, and its subsidiaries or other affiliates (Benton Oil and Gas Company and/or its subsidiaries and other affiliates, as the context may require, is/are referred to herein as the "Company"), by encouraging them to acquire shares of the $.01 par value common stock of the Company (the "Stock") through options to purchase Stock granted pursuant to the Plan ("Options"), thereby increasing such directors', employees' and consultants' proprietary interest in the business of the Company and providing them with an increased personal interest in the continued success and progress of the Company, the result of which will promote both the interests of the Company and its shareholders. Options granted under the Plan will be either options intended to qualify as incentive stock options ("ISOs") within the meaning of Section 422 of the Internal Revenue Code of 1986, as amended (the "Code"), subject to paragraph 15 or non-qualified options ("NQOs"). Each director or employee granted an Option (an "Optionee") shall enter into an agreement with the Company (the "Option Agreement") setting forth the terms and conditions of the Option, as determined in accordance with this Plan. 2. ADMINISTRATION OF PLAN This Plan shall be administered by the Compensation and Stock Option Committee of the Board of Directors of the Company (the "Committee"), to be composed of two (2) or more members of the Board of Directors of the Company who shall be appointed from time to time by the Board of Directors. The Committee shall have the sole and absolute power to make all determinations with respect to the administration of the Plan: a. Subject to the provisions of the Plan, to determine the terms and conditions, of all Options; to construe and interpret the Plan and Options granted under it; to determine the time or times an Option may be exercised, the number of shares as to which an Option may be exercised at any one time, and may when an Option may terminate; to establish, amend and revoke rules and regulations relating to the Plan and its administration; and to correct any defect, supply any omission, or reconcile any inconsistency in the Plan, or in any Option Agreement, in a manner and to the extent it shall deem necessary, all of which determinations and interpretations made by the Committee shall be conclusive and binding on all Optionees, any other holders of Option and on their legal representatives and beneficiaries; b. To determine all questions of policy and expediency that may arise in the administration of the Plan and generally exercise such powers and perform such acts as are deemed necessary or expedient to promote the best interests of the Company; and c. Except to the extent prohibited by, or impermissible in order to obtain treatment desired by the Committee under, applicable law or rule, to allocate or delegate all or any portion of its powers and responsibilities to any one or more of its members or to any person(s) selected by it, subject to revocation or modification by the Committee of such allocation or delegation. 3. SHARES SUBJECT TO THE PLAN Subject to the provisions of paragraph l3 below, the Stock which may be issued pursuant to Options granted under the Plan shall not exceed in the aggregate 2,500,000 shares. If any Options granted under the Plan terminate, expire or are surrendered without having been exercised in full, the number of shares of Stock not purchased under such Options shall be available again for the purpose of the Plan. 2 4. PERSONS ELIGIBLE FOR OPTIONS a. All directors, employees and consultants of the Company shall be eligible to receive the grant of Options under the Plan. The Committee shall determine the employees, directors and consultants to whom Options shall be granted, the time or times such Options shall be granted, the type of Option to be granted, the number of shares to be subject to each Option and the times when each Option may be exercised; provided, however, no Optionee shall be granted during any calendar year Options under the Plan to purchase more than 250,000 shares of Stock. An Optionee, if he or she is otherwise eligible, may be granted additional Options. An employee, director or consultant may be granted ISOs or NQOs or both under the Plan; provided, however, that the grant of ISOs and NQOs to an employee, director or consultant shall be the grant of separate Options and each ISO and each NQO shall be specifically designated as such in accordance with the applicable provisions of the Department of Treasury regulations. b. With respect to the granting of ISOs only, no ISO will be granted to an Optionee, and an attempted grant of such an ISO will be void, if the aggregate Fair Market Value Per Share (as defined below), determined by the Committee at the time an ISO is granted, of the Stock with respect to which the ISO and previously granted ISOs are exercisable for the first time by such Optionee during any calendar year (under all such plans of the Company) exceeds $100,000 or such other amount as may be specified in Section 422(d) of the Code. 5. PURCHASE PRICE a. The purchase price of each share of Stock covered by each ISO shall not be less than one hundred percent (100%) of the Fair Market Value Per Share (as defined below) of the Stock on the date the ISO is granted; provided, however, if when an ISO is granted the Optionee receiving the ISO owns or will be considered to own by reason of Section 424(d) of the Code more than ten percent (10%) of the total combined voting power of all classes of stock of the Company, the purchase price of the Stock covered by such ISO shall not be less than one hundred and ten percent (110%) of the Fair Market Value Per Share of the Stock on the date the ISO is granted. The purchase price of each share of Stock covered by each NQO shall be set from time to time by the Committee. b. "Fair Market Value Per Share" of the Stock shall mean: (i) if the Stock is not publicly traded, the amount determined by the Committee on the date of the grant of the Option; (ii) if the Stock is traded only otherwise than on a securities exchange and is not reported on The Nasdaq National Market ("Nasdaq"), the closing quoted selling price of the Stock on the date of grant of the Option as quoted in "pink sheets" published by the National Daily Quotation Bureau; (iii) if the Stock is traded only otherwise than on a securities exchange and is reported on Nasdaq, the closing Nasdaq reported sales price of the Stock on the date of grant of the Option, as reported in the Wall Street Journal; or (iv),if the Stock is admitted to trading on a securities exchange, the closing quoted selling price of the Stock on the date of grant of the Option, as reported in the Wall Street Journal. For purposes of Items (i) through (iv) of this paragraph, if there were no sales on the date of the grant of an Option, the Fair Market Value Per Share shall be determined by the Committee in accordance with Section 20.2031-2 of the Federal Estate Tax Regulations. 6. DURATION OF OPTIONS Subject to earlier termination as provided herein, any outstanding Option and all unexercised rights thereunder shall expire and terminate automatically upon the earlier of (i) the cessation of the employment of the Optionee by the Company for any reason other than retirement under normal Company policies, death or disability or, as to Options received as a director, the cessation of service as a director or consultant of the Company other than by reason of death or disability; (ii) the date which is three months following the effective date of the Optionee's retirement from the Company's service under normal Company policies; (iii) the date which is one year following the date on which the Optionee's service with the Company (as an employee, consultant or a director, as applicable) ceases due to death or disability, (iv) the date of expiration or termination of the Option determined by the Committee at the time the Option is granted; and (v) the tenth (10th) annual anniversary date of the granting of the Option, or, if when an ISO is granted the Optionee owns (or would be considered to own by reason of Section 424(d) of the Code) more than ten percent (10%) of the total combined voting power of all classes of stock of the Company, then on the fifth (5th) such anniversary; provided, however, that the Committee shall have the right, but 2 3 not the obligation, to extend the expiry of some or all of the Options held by an Optionee whose service with the Company as an employee, consultant or a director has ceased for any reason to a date up to the end of their original terms, notwithstanding that such Options may no longer qualify as ISOs under the Code. 7. EXERCISE OF OPTIONS An Option may be exercisable in installments or otherwise upon such terms as the Committee shall determine when the Option is granted. As a condition of the exercise, in whole or in part, of any Option, the Committee may require the Optionee to pay, in addition to the purchase price of the Stock covered by the Option, an amount equal to any Federal, state, local and foreign taxes that may be required to be withheld in connection with the exercise of such Option. Notwithstanding the foregoing, the Committee may authorize the Company's officers to establish procedures for the satisfaction of an Optionee's withholding tax liability incurred upon exercise of an Option by enabling the Optionee to authorize the Company to retain from the total number of shares to be issued pursuant to such Option exercise that number of shares (based on the then Fair Market Value Per Share as determined by the Committee) that will satisfy the withholding tax due. 8. METHOD OF EXERCISE a. When the right to purchase shares accrues, Options may be exercised by giving written notice to the Company stating the number of shares for which the Option is being exercised, accompanied by payment in full by cash, or its equivalent, acceptable to the Company, of the purchase price for the shares being purchased and, if applicable, any Federal, state, local or foreign taxes required to be withheld in accordance with the provisions of paragraph 7 above. Such additional or different procedures or requirements for the exercise of Options may be established from time to time by or as directed by the Committee. b. In the Committee's discretion, payment of the purchase price for the shares may be made in whole or in part with other shares of Stock of the Company which are free and clear of all liens and encumbrances. The value of the shares of Stock tendered in payment for the shares being purchased shall be the Fair Market Value Per Share on the date of the Optionee's notice of exercise. c. Notwithstanding the foregoing, the Company shall have the right to postpone the time of delivery of the shares for such period as may be required for the Company, with reasonable diligence, to comply with any applicable listing requirements of any national securities exchange or Nasdaq or any Federal, state, local or foreign law. If the Optionee, or other person entitled to exercise the Option, fails to timely accept delivery of and pay for the shares specified in such notice, the Committee shall have the right to terminate the Option with respect to such shares. 9. CHANGE OF CONTROL PROVISIONS a. Impact of Event. Notwithstanding any other provision of the Plan or the Option Agreement to the contrary, in the event of a Change of Control, any Options outstanding as of the date such Change in Control is determined to have occurred, and which are not then exercisable and vested, shall become fully exercisable and vested to the full extent of the original grant. b. Definition of Change in Control. For purposes of the Plan, a "Change in Control" shall mean the happening of any of the following events: (i) The acquisition by any individual, entity or group (with the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 51% or more of either (A) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (B) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); provided, however, that, for purposes of this subsection (i), the following acquisitions shall not constitute a Change of Control: (1) any acquisition directly from the Company, (2) any acquisition by the Company, (3) any acquisition by any 3 4 employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (4) any acquisition by any corporation pursuant to a transaction which complies with clauses (A), (B) and (C) of subsection (iii) of this Section 9; or (ii) Individuals who, as of the date hereof, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or (iii) Approval by the stockholders of the Company of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of assets or stock of another corporation (a "Business Combination"), in each case, unless, following such Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially won, directly or indirectly, more than 60% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (B) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (C) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or (iv) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company. 10. TRANSFERABILITY OF OPTIONS Except as otherwise determined by the Committee, no Option granted under the Plan shall be assignable or transferable by the Optionee, either voluntarily or by operation of law, other than by will or the laws of descent and distribution, and, during the lifetime of the Optionee, shall be exercisable only by the Optionee. 11. CONTINUANCE OF EMPLOYMENT Nothing contained in the Plan or in any Option granted under the Plan shall confer upon any Optionee any rights with respect to the continuation of employment by the Company or interfere in any way with the right of the Company (subject to the terms of any separate employment agreement to the contrary) at any time to terminate such employment or to increase or decrease the compensation of the Optionee from the rate in existence at the time of the granting of any Option. 12. RESTRICTIONS ON SHARES If the Company shall be advised by counsel that certain requirements under the Federal, state or foreign securities laws must be met before Stock may be issued under this Plan, the Company shall notify all persons who 4 5 have been issued Options, and the Company shall have no liability for failure to issue Stock under any exercise of Options because of delay while such requirements are being met or the inability of the Company to comply with such requirements. 13. PRIVILEGE OF STOCK OWNERSHIP No person entitled to exercise any Option granted under the Plan shall have the rights or privileges of a shareholder of the Company for any shares of Stock issuable upon exercise of such Option until such person has become the holder of record of such shares. No adjustment shall be made for dividends or other rights for which the record date is prior to the date on which such person becomes the holder of record, except as provided in paragraph 14 below. 14. ADJUSTMENT a. If the number of outstanding shares of Stock are increased or decreased, or such shares are exchanged for a different number or kind of shares or securities of the Company through reorganization, merger, recapitalization, reclassification, stock dividend, stock split, reverse stock split, combination of shares, or other similar transaction, the aggregate number of shares of Stock subject to the Plan as provided in paragraph 3 above, the maximum number of shares under Options that may be granted to an Optionee during any calendar year specified in paragraph 4(a) above, and the shares subject to issued and outstanding Options under the Plan shall be appropriately and proportionately adjusted by the Committee. Any such adjustment in an outstanding Option shall be made without change in the aggregate purchase price applicable to the unexercised portion of the Option but with an appropriate adjustment in the price for each share or other unit of any security covered by the Option. In the event the Committee determines that any dividend or other distribution (whether in the form of cash, shares of Stock, other securities, or other property), recapitalization, stock split, reverse stock split, reorganization, merger, consolidation, split-up, spin-off, combination, repurchase, or exchange of shares of Stock or other securities of the Company, issuance of warrants or other rights to purchase shares of Stock or other securities of the Company, or other similar transaction or event affects the shares of Stock or other securities or property then covered by Options such that an adjustment other than as provided in the foregoing portion of this subparagraph (a) is appropriate in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan and Options granted thereunder, then the Committee shall, in such manner as it may deem equitable, adjust any or all of (i) the number and kind of shares of stock (or other securities or property) which thereafter may be made the subject of Options, (ii) the number and kind of shares of stock (or other securities or property) subject to outstanding Options, (iii) the purchase price with respect to any outstanding Options, or, if deemed appropriate, make provision for a cash payment to the holders of outstanding Options, and (iv) the aggregate number of shares of Stock or number and kind of other securities or property subject to the Plan and the maximum number of shares or other securities or property under Options that may be granted to an Optionee during any calendar year specified in paragraph 4(a) above. b. Notwithstanding subparagraph (a) of this paragraph, upon the dissolution or liquidation of the Company, or upon a reorganization, merger or consolidation of the Company with one or more entities as a result of which the Company is not the surviving or resulting entity, or upon a sale of substantially all of the assets of the Company or the transfer of more than 80% of the then outstanding Stock of the Company to another entity or person, the Plan and any Options granted under the Plan shall terminate upon the consummation of the transaction (provided, such Options may be exercised effective simultaneously with such consummation to the extent otherwise exercisable, giving effect to any acceleration thereof by reason of such consummation), and the Committee shall have the right, but shall not be obligated, to accelerate the time in which any Option may be exercised prior to such termination, unless provision shall be made in writing in connection with such transaction for the continuance of the Plan, for the assumption of Options previously granted or the substitution for such Options of new options to purchase the stock of a successor or resulting entity, or parent or subsidiary thereof, with appropriate adjustments as to number and kind of shares and the option price, in which event the Plan and Options previously granted shall continue in the manner and under the terms so provided; provided, however, that the Committee or the Board of Directors shall have the authority to amend this paragraph to provide for a requirement that a successor or resulting entity assume any outstanding Options. 5 6 c. Adjustments under this paragraph shall be made by the Committee whose determination as to what adjustments shall be made, and the extent thereof, shall be final, binding and conclusive. No fractional shares of Stock shall be issued under the Plan or in connection with any such adjustment. 15. AMENDMENT AND TERMINATION OF PLAN AND SHAREHOLDER APPROVAL a. The Board of Directors of the Company, may, from time to time, suspend or terminate the Plan or amend or revise the terms of the Plan; provided that if and to the extent required by applicable law or rule, any such amendment to the Plan shall be subject to approval by a majority of votes cast at a meeting of shareholders at which a quorum representing a majority of the Stock is present in person or by proxy or such other vote as may be required by such law or rule. It is currently not anticipated that the Plan will be submitted to the shareholders of the Company for approval and therefore, ISO's would not be granted under the Plan. However, if the Plan is approved by the shareholders, or is otherwise eligible for ISO's, then the Options granted may be ISO's from the date of adoption forward. b. Subject to the provisions in paragraph 14 above, the Plan shall terminate on November 12, 2009. c. Subject to the provisions in paragraph 14 above, no amendment, suspension or termination of this Plan shall, without the consent of the Optionee, adversely affect the rights of such Optionee under any Option previously granted to such Optionee under the Plan. 16. EFFECTIVE DATE OF PLAN The Plan shall become effective November 12, 1999. 6 EX-10.22 4 l86922aex10-22.txt EXHIBIT 10.22 1 EXHIBIT 10.22 BENTON OIL AND GAS COMPANY NON-EMPLOYEE DIRECTOR STOCK PURCHASE PLAN 1. PURPOSE. The Purpose of this Non-Employee Director Stock Purchase Plan is to advance the interests of Benton Oil and Gas Company (the "Company") by encouraging non-employee directors of the Company to acquire a greater proprietary interest in the Company through ownership of Common Stock of the Company (the "Common Stock"). References to a "director" herein shall mean a non-employee director. 2. ELECTION TO RECEIVE STOCK. Each member of the Board of Directors of the Company who is not an employee of the Company may elect once each year prior to January 1, to be effective for the following year and until a new election is made, to receive all or a portion of the fees payable to such director in cash or in lieu of cash (if not all of the cash amount, in increments of $1,000) in restricted shares of Common Stock. The number of restricted shares of Common Stock issuable in accordance with an election hereunder shall be equal to the product of 1.5 multiplied by the dollar amount of cash that will instead be received in restricted shares, divided by the Fair Market Value of the Common Stock on the date (or scheduled date) of payment of the applicable fee, with any fraction of a share rounded down to a whole number. "Fair Market Value" of the Common Stock as of any date shall be the closing price on such date (or if no trades occurred on such date on the next preceding day on which trading occurred) as reported for consolidated transactions on the principal national securities exchange on which the Common Stock is listed or admitted to trading or on the NASDAQ Market System, or if not so listed or admitted to trading, the average of the high bid and low asked prices of the Common Stock on such date in the over-the-counter market as reported by the NASDAQ reporting system or other system then in use. Notwithstanding the foregoing, no single director may acquire more than one percent of the shares of Common Stock outstanding as of the Effective Date of the Plan (as defined herein). 3. ISSUANCE OF SHARES. On each quarterly payment date of directors' fees at which an election to receive restricted shares of Common stock is effective, for each director so electing a stock certificate evidencing the appropriate number of restricted shares shall be issued and registered in the name of the director. The stock certificates evidencing such shares shall be held in custody by the Company until the restrictions thereon shall have lapsed, after which such certificates shall be delivered to the appropriate director. The Company shall not be required to issue shares hereunder until such shares have been listed or admitted to trading on the appropriate stock exchange or trading market and the Company has complied with applicable federal and state securities laws. 4. RESTRICTIONS. Each share of Common Stock issued to a director pursuant to the Plan may not be sold, assigned, transferred, pledged, hypothecated or otherwise disposed of until a period of one year from the date of issuance or, if earlier, on the date of termination of such 2 director as a member of the Board of Directors as a result of his death, disability, removal or failure to be nominated for an additional term as a member of the Board of Directors. 5. VOTING AND DIVIDEND RIGHTS. During the period in which the restrictions provided herein are applicable to the shares of Common Stock, the director shall have the right to vote such shares and to receive any dividends paid in cash or other property with respect to such shares. Shares of Common Stock distributed by the Company as a result of any stock dividend, stock split, reclassification or other similar capital or corporate structure change shall be subject to the same restrictions as the shares with respect to which they were distributed. 6. TERMINATION OF PLAN. The Plan may be terminated at any time upon a vote of a majority of the Board of Directors to terminate the Plan. Upon termination of the Plan, restrictions on shares of Common Stock shall continue in effect and shall lapse in accordance with the terms of the Plan at the time of issuance of such shares. 7. EFFECTIVE DATE. The Plan shall become effective on January 5, 2001. -2- EX-10.23 5 l86922aex10-23.txt EXHIBIT 10.23 1 EXHIBIT 10.23 BENTON OIL AND GAS COMPANY EMPLOYMENT AGREEMENT FOR STEVE W. THOLEN This Employment Agreement (the "Agreement") is entered into as of December 7, 2000 by BENTON OIL AND GAS COMPANY, a Delaware corporation ("Company") and STEVE W. THOLEN ("Employee"). In consideration of the promises below, the parties agree as follows. 1. TITLE. Employee shall hold the title of Senior Vice President and Chief Financial Officer. 2. DUTIES. 2.1. GENERAL DUTIES. Employee shall undertake and render services as may from time to time be assigned to him by the Chief Executive Officer. The duties shall be reasonably consistent with Employee's experiences. 2.2. OUTSIDE ACTIVITIES. Employee shall devote his full time to the performance of his duties, and agrees that his first duty of loyalty is to Company. Except with the express written consent of the Board of Directors, Employee shall not, directly or indirectly, alone or as a member of any partnership, or as an officer, director or employee of any other corporation, partnership or other organization, be actively engaged in any other duties or pursuits which interfere or compete with the performance of his duties under this Agreement. 3. TERM. This Agreement shall commence on January 1, 2001 and continue in force until December 31, 2002 (the "Employment Period") unless sooner terminated by either party pursuant to Section 5. 4. COMPENSATION. As payment in full for services rendered to Company, Employee shall be entitled to receive from Company, and Company shall pay to Employee, salary and benefits as follows. 4.1. SALARY. Company shall initially pay to Employee base salary at a rate of $250,000 per annum ("Base Salary") payable bi-weekly or at such other time or times as Company may allow or provide to other similarly situated employees in accordance with policies adopted from time to time by the Board of Directors. Base Salary for any partial period of employment shall be prorated. All compensation shall be subject to deductions or withholding for taxes. Company shall annually review Employee's salary. 1 2 4.2. ANNUAL INCENTIVE COMPENSATION. Employee shall be entitled to an annual bonus (the "Annual Bonus") as determined by the Compensation Committee of the Company's Board of Directors (the "Compensation Committee"). Such Annual Bonus for 2001 shall include, but is not limited to, the issuance of options equal to $117,800 divided by the fair market value of the Company's common stock on the date of the grant of the Annual Bonus. The final structure and terms of said Bonus Plan will be agreed upon between the CEO and Compensation Committee by January 31, 2001. 4.3. EQUITY COMPENSATION. As of the Commencement Date, the Company shall issue stock options (the "Options") to purchase shares of the Company's common stock under the Company's Stock Option Plan. The initial grant shall be Options to purchase 150,000 shares of the Company's stock. 4.4. FRINGE BENEFITS. Employee shall be entitled to annual vacation of four (4) weeks per year and to receive employee and fringe benefits including but not limited to any compensation plan such as an incentive stock option, restricted stock or stock purchase plan or any employee benefit plan such as a thrift, pension, profit sharing, medical disability, accident, plan program or policy (the Company's "Plans") as Company may allow or provide to other similarly situated employees in accordance with policies adopted from time to time by the Board of Directors. 4.5. EXPENSES REIMBURSEMENT. Employee shall be reimbursed for all direct, out-of-pocket business expenses incurred by him in connection with his employment (including, without limitation, expenses for travel and entertainment incurred in conducting or promoting business for the Company), upon timely submission by the Employee of receipts and other documentation, and in accordance with the normal expense reimbursement policy of the Company. In connection with Employees relocation, the Company shall reimburse Employee for the following: (1) all costs of temporary housing in California for a period of up to four (4) weeks; (2) all moving expenses (limited to $20,000), including closing costs (exclusive of real estate commissions) to sell one home and purchase another home. 4.6. SICKNESS AND DISABILITY. Except as set forth in Section 5.2, Employee shall receive full compensation for any period of illness or incapacity during the term of this Agreement. 4.7. HOLIDAYS. Employee shall be entitled to holidays recognized as State and/or National holidays and as Company may allow or provide in accordance with policies adopted from time to time by the Board of Directors. 5. TERMINATION OF EMPLOYMENT. The following provisions shall apply in the event of termination of Employee's employment for any reason. 5.1. RIGHT TO TERMINATE BY COMPANY. Company may terminate Employee's Agreement, by action of its Board of Directors, immediately upon written notice of termination 2 3 for Cause or upon thirty (30) days notice for any other reason. The term "Cause" when referring to termination by Company means only the following and any other termination shall be without Cause: (i) any act of personal dishonesty taken by the Employee in connection with his responsibilities as an Employee which is intended to result in substantial personal enrichment to the Employee; (ii) Employee's conviction of a felony which the Board responsibly believes has had or will have a material detrimental effect on the Company's reputation or business; (iii) a willful act by the Employee which constitutes misconduct and is injurious to the Company; and (iv) continued willful violations by the Employee of the Employee's obligations to the Company after there has been delivered to Employee a written demand for performance from the Company which describes the basis for the Company's belief that the Employee has not substantially performed his duties. 5.2. TERMINATION FOR DEATH OR DISABILITY. Employee's employment shall terminate upon the earliest of the events specified below: (i) the death of Employee; (ii) the date of termination specified in a written notice of termination by reason of physical or mental condition of Employee which shall substantially incapacitate him from performing his principal duties delivered by the Company to Employee at least 30 days prior to the date specified in the notice, which shall be any date after the expiration of any 120 consecutive days during which Employee shall be unable, by reason of his disability, to perform his principal duties, provided however, that such notice shall be null and void if Employee fully resumes the performance of his duties under this Agreement prior to the date of termination set forth in the notice. 5.3. TERMINATION BY EMPLOYEE. If an Involuntary Termination has occurred, Employee shall be entitled to terminate his employment and to receive compensation equal to such compensation provided in Section 6.3. If Employee terminates his employment for any reason other than death, disability or Involuntary Termination, then Employee shall provide the Company with thirty (30) days prior notice and Employee shall be paid his compensation until the effective date of termination. 6. CHANGE OF CONTROL AND INVOLUNTARY TERMINATION. 6.1. DEFINITION OF TERMS. The following terms referred to in this Agreement shall have the following meanings: (i) CHANGE OF CONTROL. "Change of Control" shall mean the occurrence of any of the following events: (a) the approval by shareholders of the Company of a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) more than fifty percent 3 4 (50%) of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; (b) any approval by the shareholders of the Company of a plan of complete liquidation of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company's assets; (c) any "person" (as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended) becoming the "beneficial owner" (as defined in Rule 13d-3 under said Act), directly or indirectly, of securities of the Company representing 25% or more of the total voting power represented by the Company's then outstanding voting securities; or (d) a change in the composition of the Board, as a result of which fewer than a majority of the directors are Incumbent Directors. "Incumbent Directors" shall mean directors who either (A) are directors of the Company as of the date hereof, or (B) are elected, or nominated for election, to the Board with the affirmative votes of at least a majority of those directors whose election or nomination was not in connection with any transaction described in subsections (a), (b) or (c) or in connection with an actual or threatened proxy contest relating to the election of directors of the Company. (ii) INVOLUNTARY TERMINATION. "Involuntary Termination" shall mean (a) without the Employee's express written consent, a significant reduction of the Employee's duties, position or responsibilities relative to the Employee's duties, position or responsibilities in effect immediately prior to such reduction, or the removal of the Employee from such position, duties and responsibilities, unless the Employee is provided with comparable duties, position and responsibilities; (b) without the Employee's express written consent, a substantial reduction, without good business reasons, of the facilities and perquisites (including office space and location) available to the Employee immediately prior to such reduction; (c) a reduction by the Company of the Employee's Base Salary as in effect immediately prior to such reduction; (d) a material reduction by the Company in the kind or level of employee benefits to which the Employee is entitled immediately prior to such reduction with the result that the Employee's overall benefits package is significantly reduced; (e) without the Employee's express written consent, the relocation of the Employee to a facility or a location more than fifty (50) miles from the location of the Company's principal office; (f) any purported termination of the Employee by the Company which is not effected for Cause or for which the grounds relied upon are not valid; or (g) the failure of the Company to obtain the assumption of this Agreement by any successors contemplated in Section 7(i). 6.2. PAYMENTS UPON TERMINATION. (i) SEVERANCE PAYMENTS. If the Employee's employment with the Company terminates as a result of an Involuntary Termination at any time after a Change of Control, then the Employee shall be entitled to receive a lump sum payment equal to one (1) times Employee's annual Base Salary at the rate in effect just prior to the date of the notice of termination. Such amount shall be in addition to any amounts due under this agreement. 4 5 Such severance payments shall be paid in a single lump sum within thirty (30) days of such termination. In addition, the Company shall continue to make available to the Employee and Employee's spouse and dependents covered under any group health plans or life insurance plans of the Company on the date of such termination of employment, all group health, life and other similar insurance plans in which Employee or such covered dependents participate on the date of the Employee's termination for a period of twelve (12) months on the same basis as provided on the date of termination. (ii) OPTION ACCELERATION. If the Employee's employment with the Company terminates as a result of an Involuntary Termination at any time after a Change of Control, then the vesting and exercisability of each option granted to the Employee by the Company (the "Options") shall be automatically accelerated in full. 6.3. PAYMENTS ON OTHER TERMINATION. If the Employee's employment with the Company terminates as a result of an Involuntary Termination, other than as a result of an Involuntary Termination after a Change of Control, or termination by the Company without Cause, then the Employee shall not be entitled to receive severance or other benefits hereunder, other than payments through the end of this Agreement, or for one year, whichever is longer. If termination is for Cause, Employee shall be paid his Base Salary to the date of the notice of termination. 6.4. ACCRUED WAGES AND VACATION; Expenses. Without regard to the reason for, or the timing of, Employee's termination of employment: (a) the Company shall pay the Employee any unpaid base salary due for periods prior to the date of termination; (b) the Company shall pay the Employee all of the Employee's accrued and unused vacation through the date of termination; and (c) following submission of proper expense reports by the Employee, the Company shall reimburse the Employee for all expenses reasonably and necessarily incurred by the Employee in connection with the business of the Company prior to the date of termination. These payments shall be made promptly upon termination and with the period of time mandated by law. 7. SUCCESSORS. (i) COMPANY'S SUCCESSORS. Any successor to the Company (whether direct or indirect and whether by purchase, lease, merger, consolidation, liquidation or otherwise) to all or substantially all of the Company's business and/or assets shall assume the Company's obligations under this Agreement and agree expressly to perform the Company's obligations under this Agreement in the same manner and to the same extent as the Company would be required to perform such obligations in the absence of a succession. For all purposes under this Agreement, the term "Company" shall include any successor to the Company's business and/or assets which executes and delivers the assumption agreement described in this section or which becomes bound by the terms of this Agreement by operation of law. (ii) EMPLOYEE'S SUCCESSORS. Without the written consent of the Company, Employee shall not assign or transfer this Agreement or any right or obligation under this Agreement to any other person or entity. Notwithstanding the foregoing, the terms of this 5 6 Agreement and all rights of Employee hereunder shall inure to the benefit of, and be enforceable by, Employee's personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. 8. NOTICES. (i) GENERAL. Notices and all other communications contemplated by this Agreement shall be in writing and shall be deemed to have been duly given when personally delivered or when mailed by U.S. registered or certified mail, return receipt requested and postage prepaid. In the case of the Employee, mailed notices shall be addressed to him at the home address that he most recently communicated to the Company in writing. In the case of the Company, mailed notices shall be addressed to its corporate headquarters, and all notices shall be directed to the attention of its Secretary. (ii) NOTICE OF TERMINATION. Any termination by the Company for cause or by the Employee as a result of a voluntary resignation or an Involuntary Termination shall be communicated by a notice of termination to the other party hereto given in accordance with this Section. Such notice shall indicate the specific termination provision in this Agreement relied upon, shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination under the provision so indicated. The failure by the Employee to include in the notice any fact or circumstance which contributes to a showing of Involuntary Termination shall not waive any right of the Employee hereunder or preclude the Employee from asserting such fact or circumstance in enforcing his rights hereunder. 9. ARBITRATION. (i) Any dispute or controversy arising out of, relating to, or in connection with this Agreement, or the interpretation, validity, construction, performance, breach, or termination thereof, shall be settled by binding arbitration to be held in Houston, Texas, in accordance with the National Rules for the Resolution of Employment Disputes then in effect of the American Arbitration Association (the "Rules"). The arbitrator may grant injunctions or other relief in such dispute or controversy. The decision of the arbitrator shall be final, conclusive and binding on the parties to the arbitration. Judgment may be entered on the arbitrator's decision in any court having jurisdiction. (ii) The arbitrator(s) shall apply Texas law to the merits of any dispute or claim, without reference to conflicts of law rules. The arbitration proceedings shall be governed by federal arbitration law and by the Rules, without reference to state arbitration law. Employee hereby consents to the personal jurisdiction of the state and federal courts located in Texas for any action or proceeding arising from or relating to this Agreement or relating to any arbitration in which the parties are participants. (iii) EMPLOYEE HAS READ AND UNDERSTANDS THIS SECTION, WHICH DISCUSSES ARBITRATION. EMPLOYEE UNDERSTANDS THAT SUBMITTING ANY CLAIMS ARISING OUT OF, RELATING TO, OR IN CONNECTION WITH THIS AGREEMENT, OR THE INTERPRETATION, VALIDITY, CONSTRUCTION, 6 7 PERFORMANCE, BREACH OR TERMINATION THEREOF TO BINDING ARBITRATION TO THE EXTENT PERMITTED BY LAW, AND THAT THIS ARBITRATION CLAUSE CONSTITUTES A WAIVER OF EMPLOYEE'S RIGHT TO A JURY TRIAL AND RELATES TO THE RESOLUTION OF ALL DISPUTES RELATING TO ALL ASPECTS OF THE EMPLOYER/EMPLOYEE RELATIONSHIP, INCLUDING BUT NOT LIMITED TO, THE FOLLOWING CLAIMS: (a) ANY AND ALL CLAIMS FOR WRONGFUL DISCHARGE OF EMPLOYMENT; BREACH OF CONTRACT, BOTH EXPRESS AND IMPLIED; BREACH OF THE COVENANT OF GOOD FAITH AND FAIR DEALING, BOTH EXPRESS AND IMPLIED; NEGLIGENT OR INTENTIONAL INFLICTION OF EMOTIONAL DISTRESS; NEGLIGENT OR INTENTIONAL MISREPRESENTATION; NEGLIGENT OR INTENTIONAL INTERFERENCE WITH CONTRACT OR PROSPECTIVE ECONOMIC ADVANTAGE; AND DEFAMATION. (b) ANY AND ALL CLAIMS FOR VIOLATION OF ANY FEDERAL, STATE OR MUNICIPAL STATUTE, INCLUDING, BUT NOT LIMITED TO, TITLE VII OF THE CIVIL RIGHTS ACT OF 1964, THE CIVIL RIGHTS ACT OF 1991, THE AGE DISCRIMINATION IN EMPLOYMENT ACT OF 1967, THE AMERICANS WITH DISABILITIES ACT OF 1990, THE FAIR LABOR STANDARDS ACT, THE CALIFORNIA FAIR EMPLOYMENT AND HOUSING ACT, AND LABOR CODE SECTION 201, ET SEQ.; (c) ANY AND ALL CLAIMS ARISING OUT OF ANY OTHER LAWS AND REGULATIONS RELATING TO EMPLOYMENT OR EMPLOYMENT DISCRIMINATION. 10. MISCELLANEOUS PROVISIONS. (i) NO DUTY TO MITIGATE. The Employee shall not be required to mitigate the amount of any payment contemplated by this Agreement, nor shall any such payment be reduced by any earnings that the Employee may receive from any other source. (ii) WAIVER. No provision of this Agreement may be modified, waived or discharged unless the modification, waiver or discharge is agreed to in writing and signed by the Employee and by an authorized officer of the Company (other than the Employee). No waiver by either party of any breach of, or of compliance with, any condition or provision of this Agreement by the other party shall be considered a waiver of any other condition or provision or of the same condition or provision at another time. (iii) INTEGRATION. This Agreement and the stock option agreements representing the Options represent the entire agreement and understanding between the parties as to the subject matter herein and supersede all prior or contemporaneous agreements, whether written or oral. 7 8 (iv) CHOICE OF LAW. The validity, interpretation, construction and performance of this Agreement shall be governed by the internal substantive laws, but not the conflicts of law rules, of the State of Texas. (v) SEVERABILITY. The invalidity or unenforceability of any provision or provisions of this Agreement shall not affect the validity or enforceability of any other provision hereof, which shall remain in full force and effect. (vi) EMPLOYMENT TAXES. All payments made pursuant to this Agreement shall be subject to withholding of applicable income and employment taxes. (vii) COUNTERPARTS. This Agreement may be executed in counterparts, each of which shall be deemed an original, but all of which together will constitute one and the same instrument. IN WITNESS WHEREOF, each of the parties has executed this Agreement, in the case of the Company by its duly authorized officer, as of the day and year first above written. COMPANY: BENTON OIL AND GAS COMPANY By:___________________________ Peter J. Hill Chief Executive Officer EMPLOYEE: ______________________________ STEVE W. THOLEN 8 EX-21.1 6 l86922aex21-1.txt EXHIBIT 21.1 1 EXHIBIT 21.1 BENTON OIL AND GAS COMPANY LIST OF SUBSIDIARIES --------------------
JURISDICTION NAME OF INCORPORATION ----------------------------------------------------- ----------------------------------- Benton-Vinccler, C.A.* Venezuela Energy International Financial Institution, Ltd.* Cayman Islands Benton Offshore China Company Colorado Benton Offshore China Holding Company Delaware Geoilbent, Ltd.* Russia Arctic Gas Company* Russia
The names of certain subsidiaries have been omitted in reliance upon Item 601(b)(21)(ii) of Regulation S-K. *All subsidiaries are wholly-owned by Benton Oil and Gas Company, except Benton-Vinccler, C.A. and Energy International Financial Institution which are owned 80 percent by Benton Oil and Gas Company, Geoilbent, Ltd. which is owned 34 percent by Benton Oil and Gas Company and Arctic Gas Company which is owned 24 percent by Benton Oil and Gas Company. EX-23.1 7 l86922aex23-1.txt EXHIBIT 23.1 1 EXHIBIT 23.1 BENTON OIL AND GAS COMPANY CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-37124, 333-49114, 333-19679, and 333-94823), Form S-3 (Nos. 33-70146, 333-00135 and 333-17231) and Form S-4 (Nos. 33-61299, 33-42139 and 333-06125) of Benton Oil and Gas Company of our report dated March 23, 2001 relating to the financial statements and financial statement schedule, which appears in this Form 10-K. PricewaterhouseCoopers LLP Los Angeles, California April 2, 2001 EX-23.2 8 l86922aex23-2.txt EXHIBIT 23.2 1 EXHIBIT 23.2 BENTON OIL AND GAS COMPANY INDEPENDENT PETROLEUM ENGINEERS' CONSENT Huddleston & Co., Inc., hereby consents to the use of its name in reference to it regarding its audit of the Benton Oil and Gas Company reserve reports dated as of December 31, 1999, 1998, and 1997; in the Form 10-K Annual Report of Benton Oil and Gas Company to be filed with the Securities and Exchange Commission. Peter D. Huddleston, P.E. Huddleston & Co., Inc. Houston, Texas March 28, 2001 EX-23.3 9 l86922aex23-3.txt EXHIBIT 23.3 1 EXHIBIT 23.3 BENTON OIL AND GAS COMPANY INDEPENDENT PETROLEUM ENGINEERS' CONSENT ---------------------------------------- Ryder Scott Company, L.P. hereby consents to the use of its name in reference to its preparation of the Benton Oil and Gas Company reserve report, dated as of December 31, 2000, in the Form 10-K Annual Report of Benton Oil and Gas Company to be filed with the Security and Exchange Commission. Ryder Scott Company, L.P. Denver, Colorado March 23, 2001 -----END PRIVACY-ENHANCED MESSAGE-----