-----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, Cw/SqGWhqacSp6eaSb0UDX00YY5PBb1lM3ArruX6Bdggt5mXkW4/oC4OAcOmyYha GpvS/geKaZId7H87oiOncQ== 0000950152-99-002882.txt : 19990402 0000950152-99-002882.hdr.sgml : 19990402 ACCESSION NUMBER: 0000950152-99-002882 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990331 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-K405 SEC ACT: SEC FILE NUMBER: 001-10762 FILM NUMBER: 99581857 BUSINESS ADDRESS: STREET 1: 1145 EUGENIA PL STREET 2: STE 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-K405 1 BENTON OIL AND GAS COMPANY FORM 10-K405 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, 1998 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 INCORPORATION OR ORGANIZATION) (IRS Employer Identification Number) 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: NONE Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED - ------------------- ----------------------------------------- Common Stock, $.01 Par Value NYSE Common Stock Purchase Warrants, $11.00 exercise price NASDAQ
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 24, 1999, the aggregate market value of the shares of voting stock of Registrant held by non-affiliates was approximately $104,882,872 based on a closing sales price on NYSE of $3.63. As of March 24, 1999, 29,576,966 shares of the Registrant's common stock were outstanding. DOCUMENT INCORPORATED BY REFERENCE Portions of the Registrant's Proxy Statement for the 1999 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.[X] 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....................................................32 Item 8. Financial Statements and Supplementary Data.................................33 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ........................33 Part III - -------- Item 10. Directors and Executive Officers of the Registrant .........................34 Item 11. Executive Compensation......................................................34 Item 12. Security Ownership of Certain Beneficial Owners and Management..........................................34 Item 13. Certain Relationships and Related Transactions .............................34 Part IV - ------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................................35 Financial Statements.......................................................................37 Signatures.................................................................................66
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 gas wells, the price for oil and natural gas, and other risks indicated in 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 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. ITEM 1. BUSINESS GENERAL Benton Oil and Gas Company (the "Company") is an independent energy company which has been engaged in the development and production of oil and gas properties since 1989. The Company has developed significant interests in Venezuela and Russia, and has acquired certain interests in China, Jordan, Senegal and the United States. The Company's producing operations are conducted principally through its 80%-owned Venezuelan subsidiary, Benton-Vinccler, C.A. ("Benton-Vinccler"), which operates the South Monagas Unit in Venezuela, and its 34%-owned Russian joint venture, GEOILBENT, which operates the North Gubkinskoye Field in West Siberia, Russia. The Company has expanded into projects which involve exploration components in Russia through its ownership interest in Severneftegaz; in China, through a farmout agreement with Shell Exploration (China) Limited ("Shell") and the acquisition of the WAB-21 Exploration Block; in Venezuela through its participation in the Delta Centro Exploration Block; in both onshore and offshore Senegal; in the Sirhan Block in Southern Jordan; and in Santa Barbara County, California through the acquisition of three state offshore oil and gas leases. As of December 31, 1998, the Company had total assets of $338.6 million, total estimated proved reserves of 168.9 MMBOE, and a standardized measure of discounted future net cash flow, before income taxes, for total proved reserves of $112.0 million. For the year ended December 31, 1998, the Company had total revenues of $112.1 million. The Company was incorporated in Delaware in September 1988. Its principal executive offices are located at 6267 Carpinteria Avenue, Suite 200, Carpinteria, California 93013, and its telephone number is (805) 566-5600. BUSINESS STRATEGY The Company's business strategy is to identify and exploit new oil and gas reserves primarily in under-developed but proven hydrocarbon regions thereby seeking to minimize the associated risk of such activities. Specifically, the Company endeavors to minimize risk by employing the following strategies in its business activities: (i) seek new reserves primarily in areas of low geologic risk; (ii) use proven advanced technology in both exploration and development to maximize recovery, including the exploration of higher risk, higher potential areas; (iii) establish a local presence through joint venture partners and the use of local personnel; (iv) commit capital in a phased manner to limit total commitments at any one time; and (v) reduce foreign exchange risks through receipt of revenues in U.S. currency. 4 4 SEEK NEW RESERVES IN AREAS OF LOW GEOLOGIC RISK. The Company has had significant success in identifying under-developed reserves in the U.S. and internationally. In particular, the Company has notable experience and expertise in seeking and developing new reserves in countries where perceived potential political and operating difficulties have sometimes discouraged other energy companies from competing. As a result, the Company has established operations in Venezuela and Russia, which have significant reserves that have been acquired and are being developed at relatively low costs. USE OF PROVEN ADVANCED TECHNOLOGY IN BOTH EXPLORATION AND DEVELOPMENT. The Company's use of 3-D seismic technology, in which a three dimensional image of the earth's subsurface is created through the computer interpretation of seismic data, combined with its experience in designing the seismic surveys and interpreting and analyzing the resulting data, allow for a more detailed understanding of the subsurface than do conventional surveys. Such technology contributes significantly to field appraisal, development and production. The 3-D seismic information, in conjunction with subsurface geologic data from previously drilled wells, is used by the Company's experienced in-house technical team to identify previously undetected reserves. The 3-D seismic information can also be used to guide drilling on a real-time basis, and has been especially helpful in the horizontal drilling done in Venezuela in order to take advantage of oil-trapping faults. ESTABLISH A LOCAL PRESENCE THROUGH JOINT VENTURE PARTNERS AND THE USE OF LOCAL PERSONNEL. The Company has sought to establish a local presence where it does business to facilitate stronger relationships with the local governments and labor organizations through joint venture arrangements with local partners. Moreover, the Company employs almost exclusively local personnel to run foreign operations both to take advantage of local knowledge and experience and to minimize cost. These efforts have created an expertise within Company management in forming effective foreign partnerships and operating abroad. The Company believes that it has gained access to new development opportunities as a result of its reputation as a dependable partner. COMMIT CAPITAL IN A PHASED MANNER TO LIMIT TOTAL COMMITMENTS AT ANY ONE TIME. While the Company typically has agreed to a minimum capital expenditure or development commitment at the outset of new projects, expenditures to fulfill these commitments are phased over time. In addition, the Company seeks, where possible, to use internally generated funds for further capital expenditures and to invest in projects which provide the potential for an early return to the Company. REDUCE FOREIGN EXCHANGE RISKS. The Company seeks to reduce foreign currency exchange risks by providing for the receipt of revenues in U.S. dollars while most operating costs are incurred in local currency. Pursuant to the operating service agreement between Benton-Vinccler and Lagoven, S. A., then one of three exploration and production affiliates of the national oil company Petroleos de Venezuela, S.A. which have subsequently all been combined into PDVSA Petroleo y Gas, S.A. (all such parent, subsidiary and affiliated entities hereinafter referred to as "PDVSA"), the operating fees earned by Benton-Vinccler are paid directly to Benton-Vinccler's bank account in the United States in U.S. dollars. GEOILBENT receives revenues from export sales in U.S. dollars paid to its account in Moscow. As the Company continues to expand internationally, it will seek to establish similar arrangements for new operations. PRINCIPAL AREAS OF ACTIVITY The following table summarizes the Company's proved reserves, drilling and production activity, and financial operating data by principal geographic area at and for each of the years ended December 31:
VENEZUELA (1) RUSSIA (2) ----------------------------- ------------------------------ (dollars in 000's) 1998 1997 1996 1998 1997 1996 ---- ---- ---- ---- ---- ---- RESERVE INFORMATION: Proved Reserves (MBOE) 137,835 94,671 86,076 31,053 26,113 23,544 Discounted Future Net Cash Flow Attributable to Proved Reserves, Before Income Taxes $ 62,455 $364,038 $446,854 $ 49,546 $77,696 $90,705 Standardized Measure of Future Net Cash Flows $ 62,455 $291,471 $323,550 $43,248 $63,433 $73,423 DRILLING AND PRODUCTION ACTIVITY: Gross Wells Drilled 16 27 33 31 7 5 Average Daily Production (BOE) 33,349 42,178 34,557 2,530 2,411 2,091
5 5
VENEZUELA (1) RUSSIA (2) ------------------------------- --------------------------------- (dollars in 000's) 1998 1997 1996 1998 1997 1996 ---- ---- ---- ---- ---- ---- FINANCIAL DATA: Oil and Gas Revenues $ 82,215 $154,119 $136,840 $8,059 $9,925 $9,047 Expenses: Lease Operating Costs and Production Taxes 39,069 34,516 17,669 5,626 7,349 6,605 Depletion 31,843 43,584 29,523 2,474 3,079 2,747 Write down of oil and gas properties 187,811 - - 10,100 - - Income tax expense (benefit) (26,793) 25,656 24,429 - - - --------- ------- ------- -------- ------ ----- Total Expenses 231,930 103,756 71,621 18,200 10,428 9,352 --------- ------- ------- -------- ------ ----- Results of Operations from Oil and Gas Producing Activities $(149,715) $50,363 $65,219 $ (10,141) $ (503) $ (305) ========= ======= ======= ========= ====== ======
[FN] (1) Includes 100% of the reserve information, drilling and production activity and financial data, without deduction for minority interest. 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. See "--South Monagas Unit, Venezuela." (2) The financial information for Russia includes the Company's 34% share of the information for the twelve months ended September 30, 1996, 1997 and 1998, the end of the fiscal period for GEOILBENT. SOUTH MONAGAS UNIT, VENEZUELA GENERAL In July 1992, the Company and Venezolana de Inversiones y Construcciones Clerico, C.A. ("Vinccler"), a Venezuelan construction and engineering company, signed a 20-year operating service agreement with PDVSA to reactivate and further develop the Uracoa, Tucupita and Bombal Fields, which are a part of the South Monagas Unit (the "Unit"). At that time, the Company was one of three foreign companies ultimately awarded an operating service agreement to reactivate existing fields by PDVSA, and was the first U.S. company since 1976 to be granted such an oil field development contract in Venezuela. The oil and gas operations in the Unit are conducted by Benton-Vinccler, the Company's 80%-owned subsidiary. The remaining 20% of the outstanding capital stock of Benton-Vinccler is owned by Vinccler. The Company, through its majority ownership of stock in Benton-Vinccler, makes 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 continues to provide ongoing assistance with construction services and governmental and labor relations. Under the terms of the operating service agreement, Benton-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. In addition, PDVSA maintains full ownership of equipment and capital infrastructure following its installation. Benton-Vinccler invoices PDVSA each quarter based on Bbls of oil accepted by PDVSA during the quarter, using quarterly adjusted contract service fees per Bbl, and 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 Bbl of crude oil delivered and 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 Bbl set forth in the agreement. The operating fee is subject to periodic adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index, and the maximum total fee is subject to periodic adjustments to reflect changes in the average of certain world crude oil prices. Since commencement of operations, the Company has received approximately $11 million in capital recovery fees. Based on crude oil prices as of December 31, 1998, the maximum total fee provided for no capital recovery. The Company cannot predict the extent to which future maximum total fee adjustments will provide for capital recovery components in the fees it receives, and has recorded no asset for future capital recovery fees. 6 6 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, 1998, proved reserves attributable to the Company's Venezuelan operations were 137,835 MBOE, which represented approximately 82% of the Company's proved reserves. Benton-Vinccler is currently developing the Oficina sands in the Uracoa Field, which contain 84% of the Unit's proved reserves and has begun the development of the Tucupita and Bombal Fields which contain the remaining 16% of the Unit's reserves. The associated natural gas produced at Uracoa is currently being reinjected into the field, as no ready market exists for the natural gas. DRILLING AND DEVELOPMENT ACTIVITY Uracoa Field Benton-Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field. During March 1999 (through March 24), a total of approximately 93 wells were producing an average of approximately 22,184 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:
WELLS DRILLED ---------------------------------- AVERAGE DAILY VERTICAL HORIZONTAL PRODUCTION FROM FIELD (BBL) ---------------- -------------- ---------------------------------- 1996: First Quarter 1 8 29,600 Second Quarter 5 4 33,700 Third Quarter 2 7 37,700 Fourth Quarter 1 4 37,500 1997: First Quarter 2 6 36,100 Second Quarter 4 4 35,800 Third Quarter 1 6 40,500 Fourth Quarter 1 2 44,400 1998: First Quarter - - 37,700 Second Quarter - - 32,600 Third Quarter 2 - 26,500 Fourth Quarter 3 3 25,900
Daily production rates declined during the year due to a combination of production problems and deferred drilling in the fourth quarter of 1997 and first half of 1998. Drilling operations were deferred until production problems in certain wells were identified and resolved. Without continuous drilling, a mature field such as Uracoa experiences natural production declines. The natural declines were aggravated during 1998 due to the impact of the production problems on certain wells. Solutions to production problems were identified in 1998, but remediation will require work continuing into 1999. Additionally, the Company focused its efforts on the completion of a detailed geologic and reservoir simulation study during 1998. Drilling resumed in the second half of 1998, but the pace of drilling has been constrained due to uncertainties in oil prices and cash flows. Benton-Vinccler contracts with third parties for drilling and completion of wells. Currently, Helmerich & Payne International Drilling Co. is performing drilling services for Benton-Vinccler. The Company's technical personnel identify drilling locations, specify the drilling program and equipment to be used and monitor the drilling activities. To date, 15 previously drilled wells have been reactivated and 100 new wells have been drilled in the Uracoa Field using modern drilling and completion techniques that had not previously been utilized on the field. Ninety-nine wells, or 99%, have been completed and placed on production, and five injection wells have been drilled and six other wells converted to injectors. In December 1993, Benton-Vinccler drilled the first horizontal well in the Uracoa Field. Since the completion of this well, the Company has successfully integrated modern technology and modern drilling and completion techniques to improve the ultimate recovery. The Company has conducted a 3-D seismic survey and interpreted the seismic data over the Uracoa 7 7 Field. As a horizontal well is drilled, information regarding formations encountered by the drill bit is transmitted to the Company. Geologists, engineers and geophysicists at the Company can determine the location of the drill bit by comparing the information about the formations being drilled with the 3-D seismic data. The Company then directs the movement of the drill bit to more accurately direct the well to the expected reservoir. The Company is in the process of completing a geologic and reservoir simulation study with advanced analytical software and new core data. The geologic and reservoir simulation study indicates the viability of at least 80 additional primary infill wells in the Uracoa Field. Based on these results, approximately 80 new well locations have been identified in the Uracoa Field. Many of theses new locations are in underdeveloped sands where the model was used to optimize well spacing and location. In the more developed sands, the model was used to verify the economic viability of infill locations. Timing of the drilling of the additional well locations will depend on the Company's ability to generate sufficient cash flow from operations or to obtain additional funding from other sources. Oil produced in the Uracoa Field is transported to production facilities which were designed in the United States and installed by Benton-Vinccler. These production facilities are of the type commonly used in heavy oil production in the United States, but not previously used extensively in Venezuela to process crude oil of similar gravity or quality. The current production facilities have the capacity to process 60 MBbls of oil per day. Tucupita and Bombal Fields Before becoming inactive in 1987, the Tucupita Field had been substantially developed, producing 67.1 MMBbls of oil, 34.7 MMBbls of water and 17.6 Bcf of natural gas. Benton-Vinccler drilled a successful pilot well in late 1996 to evaluate the remaining development potential of the Tucupita Field. This well has produced at an approximate average rate of 1,896 Bbls of oil per day and 22,416 Bbls of water per day through December 1998. In 1998, initial oil rates from the horizontal wells were encouraging, but water cuts soon increased sharply. As a result, the redevelopment strategy was changed to include drilling deviated wells to allow for more effective water shut-off. The seven new deviated wells drilled in 1998 targeted underdeveloped portions of the field. Additionally, four old wells have been reactivated, bringing current production levels to 5.5 MBbls of oil per day. Produced water from Tucupita is reinjected into the aquifer to aid the natural water drive, while produced gas is being flared. The oil is trucked back to the Uracoa facilities where it is processed and shipped by pipeline to the sales point. Eleven new well locations have been identified in underdeveloped portions of the Tucupita Field, and additional viable wells are anticipated once a simulation study is completed for Tucupita. Moreover, 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, 15 wells with recompletion potential have been identified for reactivation. A combination of horizontal, deviated and vertical wells will be drilled to exploit the remaining oil reserves. Benton-Vinccler's 1999 capital expenditure budget includes the drilling of one well at an estimated cost of $0.8 million. The drilling of additional wells will depend on the Company's ability to generate sufficient cash flow from operations or to obtain additional funding from other sources. Given the results of the geologic and reservoir simulation study, Benton-Vinccler continues to analyze alternatives for barging the oil and for installing a pipeline from the Tucupita Field to the Uracoa Field. The prospective pipeline would also be used for production from the Bombal Field when it is developed. To date, the Company has drilled 1 well in the Bombal Field and reactivated another, resulting in current combined production of 750 Bbls of oil per day. Future plans include further development of the Bombal Field by drilling an additional evaluation well, at an anticipated cost of up to $1 million, the timing of which will be dependent upon operational considerations and the availability of funding. 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, which is the custody transfer point. The service agreement specifies that the oil stream may contain no more than 1% base sediment and water, and quality measurements are conducted both at Benton-Vinccler's facilities and at PDVSA's storage facility. A continuous flow measuring unit is installed at Benton-Vinccler's facility, so that quantity is monitored constantly. PDVSA provides Benton-Vinccler with a daily acknowledgment regarding the amount of oil accepted the previous day, which is reconciled to Benton-Vinccler's measurement. 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 New York. 8 8 EMPLOYEES; COMMUNITY RELATIONS Benton-Vinccler seeks to employ nationals rather than bring expatriates into the country. Presently, there are 12 full-time expatriates working with Benton-Vinccler and 165 local employees. Benton-Vinccler also conducts community relations programs, providing medical care, training, equipment and supplies, and support for local schools, in both states in which the Unit falls. DELTA CENTRO BLOCK, VENEZUELA GENERAL In January 1996, the Company and its bidding partners, Louisiana Land and Exploration, which has been subsequently acquired by Burlington Resources Inc. ("Burlington"), and Norcen Energy Company, which has been subsequently acquired by Union Pacific Resources Group Inc. ("UPR"), were awarded the right to explore and develop the Delta Centro Block in eastern Venezuela. The contract requires a minimum exploration work program consisting of completing a 550 square kilometer 3-D and a 289 kilometer 2-D seismic survey and drilling three wells to depths of 12,000 to 18,000 feet within five years. PDVSA estimated that this minimum exploration work program would cost $60.0 million, and required that the partners each post a performance surety bond or standby letter of credit for its pro rata share of the estimated work commitment expenditures. The Company provided a standby letter of credit in the amount of $18.0 million. The Company has a 30% interest in the exploration venture, with the other partners each owning a 35% interest. Under the terms of the operating agreement, which establishes the management company for the project, Burlington is the operator of the block, and therefore the Company does not exercise control of the operations of the venture. It is currently anticipated that Corporacion Venezolana del Petroleo, S.A. ("CVP"), an affiliate of PDVSA, will have a 35% interest in the management company, which will dilute the voting power of the partners on a pro rata basis. If areas within the block are deemed to be commercially viable, then the group has the right to enter into further agreements with CVP to develop those areas during the next 20-25 years. CVP would participate in the revenues and costs with an interest between 1 and 35%, at CVP's discretion. Any oil and gas produced by the Delta Centro consortium will be sold at market prices and will be subject to the oil and gas taxation regime in Venezuela and to the terms of a profit sharing agreement with PDVSA. Under the current oil and gas tax law, a royalty of up to 16.66% will be paid to the state. Under the contract bid terms, 41% of the pre-tax income will be shared with PDVSA for the period during which the first $1.0 billion of revenues is produced; thereafter, the profit sharing amount may increase to up to 50% according to a formula based on return on assets. Currently, the statutory income tax rate for oil and gas enterprises is 67.7%. Royalties and shared profits are currently deductible for tax purposes. LOCATION AND GEOLOGY The Delta Centro Block consists of approximately 2,100 square kilometers (526,000 acres) located in the delta of the Orinoco River 12 miles north of South Monagas. Although no significant exploratory activity had previously been conducted on the block prior to being made available for bids in 1995, PDVSA estimated that the area may contain recoverable oil reserves of as much as 820 MMBbls, and may be capable of producing up to 160 MBbls of oil per day. The general area of Venezuela in which the Delta Centro Block is located is known to be a significant source of hydrocarbons, evidenced by the Orinoco tar sands to the south and the El Furrial light oil trend to the northwest. Based on its geological studies of the basins in this area, the Company's technical staff believes that hydrocarbons have essentially migrated over time from the deeper Maturin Basin area of Venezuela southward toward the shallower Orinoco tar belt area. If so, then potential trapping structures and/or faults in the path of the migrating oil would serve as traps for the migrating oil and have the opportunity to be filled to their spill points. Delta Centro is directly in line with this migration path, making it an attractive exploration area. The area is mostly swampy in nature, with terrain ranging from forest in the north to savannah in the south. The marshlands in the block are similar to the transition zone areas in the Gulf of Mexico in which the Company has significant experience in seismic and drilling operations. DRILLING AND DEVELOPMENT ACTIVITY The venture has acquired a 595 square kilometer 3-D seismic survey over the southwestern portion of the Delta Centro Block and a 371 kilometer 2-D seismic survey to evaluate the remaining exploration potential of the block, at an expected total cost to the Company of approximately $8.3 million, of which $6.8 million had been spent through December 31, 1998. During the first quarter of 1999, drilling commenced on the Jarina 1-X, the first of the block's exploration wells, with a total anticipated cost 9 9 to the Company of $5.6 million. The well has a planned total depth of 15,600 feet and will take approximately 90 days to drill. As of December 31, 1998, the Company had incurred total capital expenditures of $8.2 million related to the block. COMMUNITY AND COUNTRY RELATIONS The Company conducts a community relations program in the area, providing medical care, equipment and supplies to the Warao tribe which resides in this area. NORTH GUBKINSKOYE, RUSSIA GENERAL In December 1991, the joint venture agreement forming GEOILBENT among the Company (34% interest) and two Russian partners, Purneftegazgeologia and Purneftegaz (each having a 33% interest), was registered with the Ministry of Finance of the USSR. In November 1993, the agreement was registered with the Russian Agency for International Cooperation and Development. Although GEOILBENT may only take action through the unanimous vote of the partners, the Company believes that it has developed a good relationship with its partners and has not experienced any disagreement with its partners on major operational matters. Mr. A.E. Benton, Chief Executive Officer of the Company, has consistently been elected Chairman of the general shareholders meetings since inception of GEOILBENT. 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, which covers an area approximately 15 miles long and 4 miles wide, has been delineated with over 60 exploratory wells (which tested 26 separate reservoirs) and is surrounded by large proven fields. Before commencement of GEOILBENT's operations, the North Gubkinskoye Field was one of the largest oil and gas fields in the region not under commercial production. 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 7 reservoir. The produced natural gas is currently being flared in accordance with environmental regulations. 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 1999 (through March 24), approximately 62 wells were producing an average of approximately 10.8 MBbls 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 ------------- --------------------- 1996: First Quarter 4 8,400 Second Quarter 1 7,200 Third Quarter - 7,100 Fourth Quarter - 6,500 1997: First Quarter 1 6,300 Second Quarter 2 6,800 Third Quarter 1 6,800 Fourth Quarter 3 6,600 1998: First Quarter 10 7,600 Second Quarter 9 8,600 Third Quarter 7 10,000 Fourth Quarter 5 9,900
10 10 GEOILBENT contracts with third parties for drilling and completion of wells. Supervised by a joint American and Russian management team, GEOILBENT identifies drilling locations, then uses Russian drilling rigs, upgraded by certain western technology and materials, to drill and complete a well. To date, 15 previously drilled wells have been reactivated and 89 wells have been drilled in the field, with 69 wells, or 78%, completed and placed on production. Four drilling rigs are currently working on various pads in the field. Each well is drilled to an average depth of approximately 9,000 feet measured depth and 8,000 feet true vertical depth. Oil produced from the North Gubkinskoye Field is transported to production facilities constructed and owned by GEOILBENT. Oil is then transferred to GEOILBENT's 37-mile pipeline which transports the oil from the North Gubkinskoye Field south to the main Russian oil pipeline network. The current production facilities are operating at or near capacity and will need to be expanded to accommodate production increases. GEOILBENT has obtained financing through a $65 million parallel loan facility (the "EBRD Credit Facility") for the development of the North Gubkinskoye Field from the European Bank for Reconstruction and Development (the "EBRD") and International Moscow Bank ("IMB"). $19 million has been advanced from the EBRD Credit Facility as of December 31, 1998 and in March 1999, GEOILBENT borrowed an additional 8.3 million. Additional borrowing will be based on achieving certain reserve and production milestones. GEOILBENT has a 1999 capital expenditure budget of approximately $21 million, of which $10 million would be used to drill 32 wells in the North Gubkinskoye Field and $11 million would be used for construction of production facilities. This budget will be dependent upon increased availability to draw from the EBRD Credit Facility and 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. All export oil sales are handled by trading companies such as Russoil or NAFTA Moscow. All export sales have been paid in U.S. dollars into GEOILBENT's account in Moscow. EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS Having access to the oilfield labor base in West Siberia, GEOILBENT employs Russian nationals almost exclusively. Presently, there are two full-time expatriates working with GEOILBENT and 412 local employees. The Company has conducted community relations programs in Russia, providing medical care, training, equipment and supplies in towns in which GEOILBENT personnel reside and also for the nomadic indigenous population which resides in the area of oilfield operations. ALTERNATIVES FOR NATURAL GAS RESERVES The Company and GEOILBENT estimate that substantial recoverable associated gas reserves exist in the North Gubkinskoye Field. In addition, there are substantial non-associated natural gas reserves in the field. While associated gas is currently flared in allowable amounts under permits with the Ministry of Fuel and Energy, Geoilbent is moving forward with plans to sell such gas in the local marketplace. Discussions are underway with Gazprom, the state natural gas monopoly, for development, production and sales of both associated and non-associated gas, which together are estimated by the Company to total approximately 4.0 Tcf. First stage development of the North Gubkinskoye gas reserves would likely involve construction of a natural gas pipeline from the field to the local gas processing plant, as well as possible expansion of that plant. Preliminary analysis indicates that Geoilbent's first year capital investment in such projects could be about $10.0 million. EAST URENGOY, RUSSIA GENERAL Severneftegaz was formed in 1992 as a private company to explore and develop the Samburg and Yevo-Yakha License Blocks, which are located in the prolific Urengoy gas province of West Siberia. Under the terms of the Cooperation Agreement signed in March 1998 ("Cooperation Agreement"), the Company acquired a 40% interest in Severneftegaz in return for providing or arranging up to $100 million of credit financing for the project. 11 11 The Cooperation Agreement imposes restrictions on the sale and transfer of the initial 40% of Severneftegaz's shares acquired subject to disbursements under the credit facility. It provides that for every $2.5 million of credit made available to Severneftegaz, 1% of the Company's shares will be released from the restrictions on sale and transfer. As of December 31, 1998, the Company had provided $8.3 million of credit, of which approximately $5.6 million had been applied to the release of restrictions on the shares. As a result, 2% of the shares have been released from their restrictions. The Company, as the primary owner, controls all of Severneftegaz's expenditures, budgeting and financial planning. The Company increased its equity position to 47.5% in December 1998 and to 55% in January 1999, through additional stock acquisitions which were not part of the cooperation agreement and were not subject to any restrictions. LOCATION AND GEOLOGY The Samburg and Yevo-Yakha License Blocks comprise approximately 823,000 acres and are situated nearly 1,740 miles northeast of Moscow 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 on the Samburg and Yevo-Yakha licenses has resulted in the discovery of major reserves of gas, condensate and oil. The primary reservoirs of these fields are currently being produced in both the adjacent Urengoy Field and Rospan Block. These reserves represent strategic resources for Russian domestic energy in addition to being a high quality export product. Historic production at the Urengoy Field is now on decline, and the undeveloped reserves discovered on the adjacent Severneftegaz and Rospan Blocks are of interest to Gazprom and Russia as replacement for the production that is being lost at Urengoy. 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 gas reserves. Both license blocks occur on the eastern flank of the giant Urengoy gas field, which currently produces hydrocarbons from reservoirs similar to those found in Samburg and Yevo-Yakha. Based on geologic and geophysical studies as well as data from the 109 exploratory wells drilled to date, Russian reserve engineers estimate that Severneftegaz' licenses contain approximately 17 Tcf of gas, 780 MMBbls of condensate and 910 MMbls of oil in recoverable reserves. DRILLING AND DEVELOPMENT ACTIVITY The planning for a 13-well Samburg pilot development project is underway. The pilot project calls for the drilling of 12 additional wells, utilization of previously drilled well # 725, installation of gas processing facilities and connection into the export pipeline system. Due to their proximity to the Urengoy field and its existing infrastructure, both of Severneftegaz' blocks are well situated for fast track development. Preliminary agreements are already in place between Severneftegaz and Gazprom to allow access to existing gas and condensate pipelines and facilities that could result in product sales to European markets. The Severneftegaz blocks are located in the heart of Urengoy/Yamburg producing and support infrastructure region. Natural gas export trunklines are located 11 kilometers from the blocks. The blocks are also close to railroads for possible liquids transportation. The combination of Gazprom's shareholdings and excess trunkline capacity combine to reduce transportation risk. With production from the giant Urengoy and Yamburg Fields in decline, significant pipeline capacity is available on Gazprom's transportation system. Gazprom, which is one of the Company's strategic partners in Severneftegaz with its own 12% ownership, is actively encouraging Severneftegaz to begin developing the Samburg Field. Discussions are underway with Gazprom concerning the transportation of Severneftegaz's gas, as well as with various parties concerning the export and marketing of the gas. Actual development activities are subject to the Company's ability to provide or arrange further funding. WAB-21, SOUTH CHINA SEA GENERAL In December 1996, the Company acquired Benton Offshore China Company, formerly Crestone Energy Corporation, a privately held company headquartered in Denver, Colorado. Benton Offshore China Company's principal asset is a petroleum contract with China National Offshore Oil Company ("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. 12 12 LOCATION AND GEOLOGY The WAB-21 Contract Area (the "Contract Area") is located approximately 50 miles east of the Dai Hung (Big Bear) Oil Field. The block is adjacent to British Petroleum's recent giant 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 large 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 significant hydrocarbon potential in the Contract Area. POLITICAL CONSIDERATIONS AND RISKS China's claim of ownership of the area results from China's discovery and China's 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. The nearby Nansha Islands were formally placed under Chinese administration during the Ming Dynasty (1368-1644 AD). In 1883, Germans were banned from geologically surveying the area by the Qing court, based on Chinese sovereignty over the region. Since the establishment of Chinese government jurisdiction over the area several hundred years ago, the Nansha Islands have long been recognized as being Chinese territory. Additionally, Russian and Vietnamese maps have historically shown this area as Chinese. Significantly, even Vietnam recognized China's sovereignty of the islands from 1956 until 1975. Vietnam's former Premier Van Dong acknowledged China's Nansha Island sovereignty in a diplomatic note in 1958. In April 1994, a Chinese seismic survey ship was intercepted by Vietnamese boats in the Contract Area while attempting to conduct seismic acquisition operations. The Chinese ship returned to its port without commencing its seismic work program. China subsequently denounced Vietnam's action. Since 1994 China has maintained publicly that it is willing to discuss the joint development of the Contract Area with the Vietnamese government. However, Vietnam has granted exploration and development rights to parts of the Contract Area to Conoco Inc. Recently, high level discussions between officials of CNOOC and PetroVietnam have resulted in preliminary agreements on resolving territorial disputes in nearby areas. Significant progress has been made in the disputed Hainan Island/Gulf of Tonkin Area, and it is hoped that similar steps will be taken to resolve the issues outstanding in the South China Sea. Exploration activities in the area will be subject to the resolution of the disputes. The Company has recorded no reserves attributable to this petroleum contract. DRILLING AND DEVELOPMENT ACTIVITY Due to the sovereignty issues, the Company has been unable to pursue an aggressive exploration program during phase one of the contract. As a result, extensions have been obtained by the Company, with the current extension in effect until June 2001. China and Vietnam are now engaged in discussions to resolve the territorial dispute. The Company plans to acquire a 7,705-mile 2-D seismic survey covering the entire block. This seismic survey will cost an estimated $8 million and will enable a full evaluation of the potential for hydrocarbon traps in advance of committing to the next phase. The petroleum contract provides that once phase one is complete, an optional phase two may be entered upon relinquishment of 25% of the block. The phase two exploration commitment consists of an exploratory well drilled to 6,562 feet (2,000 meters) for a minimum commitment of $2 million followed by a 10% relinquishment within six months of completion of the well. 13 13 QINGSHUI BLOCK, CHINA GENERAL In October 1997, the Company signed a farmout agreement with Shell Exploration (China) Limited, ("Shell"), whereby the Company acquired a 50% participation interest in Shell's Liaohe area onshore exploration project in northeast China. Shell has entered into a petroleum contract with the China National Petroleum Corporation ("CNPC") to explore and develop the deep rights in the Qingshui Block, a 563 square kilometer area (approximately 140,000 acres) in the delta of the Liaohe River. The deep rights are below 3,300 and 3,500 meters. The contract requires a three-phase exploration program. Shell is the operator of the project. Pursuant to the petroleum contract, the first exploration period commenced November 1, 1996. Pursuant to the terms of the contract, a nine-month study phase required a work commitment to evaluate the deep potential of the block, with an expected minimum expenditure of $3 million. During the remainder of the first exploration phase and prior to November 1, 1999, Shell is required to drill and complete one exploratory well to a depth of 4,500 meters, with a minimum expenditure of $8 million. A two-year second exploration phase would require Shell to drill and complete one exploratory well to 4,500 meters with a minimum expenditure of $8 million. At the commencement of phase two, 10% of the phase one contract area must be relinquished. A two-year third exploration phase would require Shell to drill and complete one additional exploratory well to 4,500 meters with a minimum expenditure of $8 million. At the commencement of the third exploration phase, 30% of the phase two contract area must be relinquished. At the conclusion of each of the exploration phases, Shell will elect whether or not to continue to the next exploration phase. Following any exploration phase under the contract, the contract permits production from each oil field identified in the exploration phase for a period of 15 years. CNPC has the right to retain up to a 51% interest in the block and will pay none of the costs of the initial three exploratory wells. CNPC will thereafter pay its proportionate share of all development and operating costs in the block and will receive its proportionate share of all production from the block, including production from the initial three wells. Shell and the Company will therefore receive at least an aggregate 49% interest in the production from the block and will pay their proportionate share of all development and operating costs. Pursuant to the farmout agreement between Shell and the Company, the Company will have 50% of Shell's working interest in the block. In July 1998, the Company paid to Shell 50% of Shell's prior investment in the Block, which was approximately $4 million ($2 million to the Company). In addition, the Company agreed to pay 100% of the first $8 million of the costs for the phase one exploration period, and 100% of the first $8 million of phase two exploration costs if the well is completed as a commercial producer. If a commercial well does not result from the first phase, all subsequent costs will be shared equally. If Shell and the Company perform each of the three phases, and assuming that a commercial well results from phase one, the Company's maximum aggregate capital commitment will be $22 million. LOCATION AND GEOLOGY The petroleum contract covers the deep rights in the Qingshui Block, a 563 square kilometer area located onshore in northeast China, in the delta area of the Liaohe River, Liaoning Province. Shell's evaluation of the block is based on comprehensive data enhancement and analysis, including core evaluation, petrophysics and 2-D seismic reprocessing, 3-D seismic mapping and volume interpretation, charge modeling and dynamic reservoir simulations. DRILLING AND DEVELOPMENT ACTIVITY The first well on the Qingshui block was spudded in January 1999. Drilling is now under way on Qing-22 Deep, a fault block structure with several potential reservoirs within the target depth of 12,000 to 14,000 feet. The prospect is considered to be a relatively moderate risk exploratory play because of its well defined structure, a proven, local hydrocarbon charge, reservoir penetrations from nearby wells, and a seismic amplitude anomaly possibly attributable to the presence of hydrocarbons. Drilling is expected to take 90 days, with another 30 days for testing. If the well is successful, it is anticipated that production from this well will begin as soon as possible and that development will tie into the network of adjacent facilities and pipelines. 14 14 SANTA BARBARA COUNTY, CALIFORNIA GENERAL In March 1997, the Company acquired a 40% participation interest in three California State offshore oil and gas leases from Molino Energy Company, LLC ("Molino Energy"), which held 100% 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% participation interest in the leases, the Company became the operator of the project and paid 100% of the first $3.7 million and 53% 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. The Company's share of the drilling and testing of the 2199 #7 well was $8.5 million. In November 1998, the Company entered into an agreement to acquire Molino Energy's interest in the leases in exchange for the release of its joint interest billing obligations of approximately $1.9 million. The agreement to acquire Molino Energy's interest will be finalized upon the completion of certain lot splits and the assignment of various permits and rights. LOCATION AND GEOLOGY The Company's operating interest covers three known fields located on three adjacent state oil and gas leases off the central California coast. Each of these leases covers approximately 4,000 acres. The Molino, Gaviota and Caliente Fields have produced an aggregate of 363 Bcf of natural gas from subsea completion in the Vaqueros formation, and the deeper, Sacate/Matilija formation has produced 12 Bcf of natural gas from the Molino Field. In addition, the Monterey formation has been penetrated from all of the gas wells, but has never been produced. The Monterey formation is known as a prolific oil producer in this area. The onshore drill site has immediate access to oil and gas pipelines. DRILLING AND DEVELOPMENT ACTIVITY The 2199 #7 exploratory well was drilled to the Gaviota anticline to test four distinct sandstone intervals in the Vaqueros/Sespe, Alegria, Gaviota and Sacate/Matilija formations. Two drill stem tests spanning 1,300 vertical feet of the primary objective, the Sacate/Matilija, proved the presence of gas and condensate in a "tight" sandstone reservoir. A drill stem test in the Gaviota formation proved to be non-commercial. The well has been temporarily abandoned while the Company studies the economic benefit of alternatives, which could include hydraulic fracturing in the Sacate Matilija and/or a sidetrack to exploit the less risky reserves in the shallower Vaqueros and Alegria sandstones. If the Company does not pursue the project within a three-year period, it must be offered back to Molino Energy on farmout terms to be negotiated by the parties. SIRHAN BLOCK, JORDAN GENERAL In August 1997, the Company acquired the rights to an Exploration and Production Sharing Agreement ("PSA") with the Natural Resources Authority of Jordan ("NRA"), established by the Hashemite Kingdom of Jordan, to explore, develop, and produce the Sirhan block in southeastern Jordan. Under the terms of the PSA, the Company is obligated to make certain capital and operating expenditures in a first phase and may elect to continue into additional phases with minimum commitments as follows: $5.1 million in the first exploration phase (2 years) to perform geological studies and expenses incurred in drilling exploratory wells; $8 million in the second exploration phase (3 years) for seismic acquisitions, geological studies, and expenses incurred in drilling exploratory wells; and $10 million in the third exploration phase (3 years) for seismic acquisitions, geological studies, and expenses incurred in drilling exploratory wells. If the Company expends more than the minimum expenditure in one phase, the excess expenditure will be credited against the Company's minimum expenditure obligation during the next phase. In addition, the Company will be entitled to recover all operating costs and expenses incurred. 15 15 LOCATION AND GEOLOGY The Sirhan Block in southeastern Jordan consists of approximately 1.2 million acres (4,827 square kilometers). This block is located in the Sirhan Basin adjacent to the Jordan-Saudi Arabia border. One existing well on the block tested light oil at low rates and several additional wells encountered thick zones with indications of gas that have not been tested. DRILLING AND DEVELOPMENT ACTIVITY During the first quarter of 1998, the Company reentered two wells and tested two different reservoirs. The WS-9 and WS-10 wells did not result in the production of commercial amounts of hydrocarbons. The Company will continue to reprocess and remap seismic data and conduct geological studies on the remaining prospectivity of the block. SENEGAL, AFRICA GENERAL In December 1997, the Company was awarded a 45% working interest in the Thies Block in the western portion of Senegal by the state oil company Societe des Petroles du Senegal ("Petrosen"). The Company will serve as operator of the block. In consideration of the grant of the 45% ownership, the Company has agreed to pay 90% of the first $6 million of costs to install a pipeline and drill two wells and, if the Company elects to proceed further, to pay 67.5% of the next $6 million of costs for further exploration and development. Thereafter, the Company's share of all costs and revenues will be 45%. Additionally, the Company has obtained the exclusive right to evaluate approximately 7.5 million acres of Senegal's entire near-offshore holdings, which have been partitioned into six separate blocks. This includes the joint area shared between Senegal and Guinea-Bissau and comprises portions of the Dome Flore block. The Company will serve as operator of each of the six offshore blocks and will have an 85% participating interest with the balance held by Petrosen. The Company is obligated to spend $1 million to reprocess and evaluate existing seismic data, after which it may elect to proceed with further operations on any or all of the blocks. LOCATION AND GEOLOGY The one-million acre onshore Thies block is located immediately east of the Sebikhotane Block, which has proven production from Maastrichtian sandstones. Deeper pay potential on the block has been demonstrated by the Gadiaga #2 well, which was drilled and tested by Petrosen in March of 1997. The six near-offshore blocks include Dome Flore, one of several salt domes known to exist offshore Senegal. DRILLING AND DEVELOPMENT ACTIVITY The Company is reprocessing 1,565 kilometers of 2-D seismic data on the Thies Block prior to making a reinterpretation of the existing discoveries and planning an exploration program. In the offshore areas, the Company is reprocessing approximately 10,000 kilometers of 2-D seismic data out of a total data set of 24,000 kilometers. Following an evaluation of this data set, the Company will select certain blocks for further exploration activity. 16 16 RESERVES The following table sets forth information regarding estimates of proved reserves at December 31, 1998 prepared by the Company and audited by Huddleston & Co., Inc., independent petroleum engineers:
CRUDE OIL AND CONDENSATE (MBBL) -------------------------------------------- DEVELOPED UNDEVELOPED TOTAL --------- ----------- ----- Venezuela(1) 75,636 62,199 137,835 Russia(2) 9,745 21,308 31,053 ------ ------ ------ Total 85,381 83,507 168,888 ====== ====== =======
[FN] (1) Includes 100% of the reserve information, without deduction for minority interest. 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. See "--South Monagas Unit, Venezuela." (2) Although the Company estimates that there are substantial natural gas reserves in the North Gubkinskoye Field, no natural gas reserves have been recorded because of a lack of a ready market. Estimates of commercially recoverable oil and 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 49% of the Company's total proved reserves were undeveloped as of December 31, 1998. Therefore, the Company's actual production, revenues, severance and excise taxes, export tariffs, development expenditures, workover and remedial expenditures, abandonment expenditures and operating expenditures with respect to its reserves will likely vary from estimates, and such variances may be material. 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 revenue 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% discount factor, which is required by the Securities and Exchange Commission 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 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, 1998, the Company reported $112.0 million of discounted future net cash flows before income taxes from proved reserves based on the Commission's required calculations. 17 17 PRODUCTION, PRICES AND LIFTING COST SUMMARY The following table sets forth by country net production, average sales prices and average lifting costs of the Company for the years ended December 31, 1998, 1997 and 1996:
YEARS ENDED DECEMBER --------------------------------------------- 1998 1997 1996 ------------- ------------- ------------- VENEZUELA Net Crude Oil Production (Bbls) 12,172,352 15,394,807 12,647,987 Average Crude Oil Sales Price ($ per Bbl) $ 6.75 $10.01 $10.82 Average Lifting Costs ($ per Bbl) $ 3.21 $2.24 $1.40 RUSSIA (1) Net Crude Oil Production (Bbls) 923,602 880,148 765,137 Average Crude Oil Sales Price ($ per Bbl) $ 8.72 $11.28 $11.82 Average Lifting Costs ($ per Bbl) $ 6.09 $8.35 $8.63
[FN] (1) The presentation for Russia includes information for the twelve months ended September 30, 1996, 1997 and 1998, the end of the fiscal period for GEOILBENT. REGULATION GENERAL The Company's operations are affected by political developments and laws and regulations in the areas in which it operates. In particular, oil and 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 gas wastes, or otherwise relating to the protection of the environment, may affect the Company's operations and costs. In any country in which the Company may do business, the oil and 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 gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and gas industry increases the Company's 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 gas in the field and water disposal were $10.2 million in 1998 and are expected to be $6.2 million in 1999. 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 submits annual production and development plans, which include information necessary for permits and approvals for its planned drilling, seismic and operating activities, to local and regional governments and to the Ministry of Fuel and Energy, Committee of Geology and Ministry of Economy. GEOILBENT also submits annual production targets and quarterly export nominations for oil pipeline transportation capacity to the Ministry of Fuel and Energy. GEOILBENT is 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 must file operating and financial compliance reports with several bodies, including the Ministries of Fuel and Energy, Committee of Geology, Committee for Technical Mining Monitoring, the Ministry of Ecology, and the State Customs Committee. 18 18 DRILLING, ACQUISITION AND FINDING COSTS During the years ended December 31, 1998, 1997 and 1996, the Company spent approximately $111 million, $109 million and $108 million, respectively, for acquisitions of leases and producing properties, development and exploratory drilling, production facilities and additional development activities such as workovers and recompletions. The Company has drilled or participated in the drilling of wells as follows:
YEARS ENDED DECEMBER 31, --------------------------------------------------------------------------------------- 1998 1997 1996 --------------------------- -------------------------- --------------------------- GROSS NET GROSS NET GROSS NET ------------ ------------ ------------ ------------ ------------ ------------ WELLS DRILLED: Exploratory: Crude oil - - - - - - Natural gas - - - - 1 .375 Dry holes - - - - - - Development: Crude oil 46 22.54 31 22.040 36 26.500 Natural gas - - - - - - Dry holes - - 1 .340 - - ----------- ------------ ------------ ------------ ------------ ------------ TOTAL 46 22.54 32 22.380 37 26.875 =========== ============ ============ ============ ============ ============ AVERAGE DEPTH OF WELLS (FEET) 7,934 6,659 8,008 PRODUCING WELLS (1): Crude Oil 159 97.300 124 78.960 113 74.300 Natural Gas - - - - - -
[FN] (1) The information related to producing wells reflects wells the Company drilled, wells the Company participated in drilling and producing wells the Company acquired. At March 24, 1999, the Company was participating in the drilling of 1 well in Venezuela, 2 wells in Russia and 1 well in China. All of the Company's drilling activities are conducted on a contract basis with independent drilling contractors. The Company does not own any drilling equipment. From commencement of operations through December 31, 1998, the Company added, net of production and property sales, approximately 168.9 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 $2.17 per BOE. The Company's estimate of future development costs for its undeveloped proved reserves at December 31, 1998 was $1.70 BOE. The estimated future development costs are based upon the Company's anticipated cost of developing its non-producing proved reserves, which costs are calculated using historical costs for similar activities. 19 19 ACREAGE The following table summarizes the developed and undeveloped acreage owned, leased or under concession as of December 31, 1998.
DEVELOPED UNDEVELOPED ------------------------------ ------------------------------- GROSS NET GROSS NET -------------- ------------- -------------- ------------- Venezuela 8,090 6,472 673,188 275,903 Russia 32,700 11,118 1,577,297 647,400 China 0 0 7,609,197 7,539,638 Jordan 0 0 1,192,752 1,192,752 Senegal 1,280 576 8,594,491 8,046,047 United States 0 0 18,100 18,100 ------------- ------------- -------------- -------------- Total 42,070 18,166 19,665,025 17,719,840 ============= ============= ============== ==============
COMPETITION The Company encounters 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 the Company's competitors have financial resources, staffs and facilities substantially greater than those of the Company. EMPLOYEES AND CONSULTANTS At December 31, 1998, the Company had 75 employees augmented from time to time with independent consultants, as required. Benton-Vinccler had 165 employees, and GEOILBENT had 412 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 has obtained certain documentation from appropriate regulatory bodies in Russia which the Company believes is adequate to establish GEOILBENT's right to develop, produce and market oil and gas from the North Gubkinskoye Field in Russia. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for another one 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 the Company's interest being reduced. At the time of acquisition of undeveloped acreage in the United States, the Company conducts a limited title investigation. A title opinion from a qualified law firm is obtained prior to drilling any given U.S. prospect. Title to presently producing properties is investigated by a qualified law firm prior to purchase. The Company believes its method of investigating the title to these domestic properties is consistent with general practices in the oil and gas industry and is designed to enable the Company to acquire title which is generally considered to be acceptable in the oil and gas industry. 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 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 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 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 revenues from Proved Reserves are estimated assuming that oil and gas prices and production costs remain constant. The resulting stream of revenues is then discounted at the rate of 10% per year to obtain a present value. 3-D SEISMIC. "3-D Seismic" is the method by which a 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. UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and 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 The Company has entered into a 15 year lease agreement for office space in Carpinteria, California. The Company has leased 50,000 square feet for approximately $74,000 per month with annual rent adjustments based on certain changes in the Consumer Price Index. The Company has entered into a sublease agreement for the office space which will not be immediately needed for operations. The Company has also entered into a sublease agreement for the office space that it previously occupied. Rents for the subleases approximate the Company's lease costs of these facilities. For information concerning the location and character of the Company's oil and gas properties and interests, see Item 1. 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 the Company 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 date has been scheduled for August 9, 1999 and discovery is ongoing, but incomplete. The Company intends to vigorously contest the suit, and in management's opinion it is too early to assess the probability of an unfavorable outcome. 22 22 On June 13, 1994, Charles Agnew and other limited partners in several limited partnerships formed by the Company brought an action in the Superior Court of California, County of Ventura, against the Company for alleged actions and omissions of the Company in operating the partnerships and alleged misrepresentations made by the Company in selling the limited partnership interests. The claimants seek an unspecified amount of actual and punitive damages. On May 17, 1995, the Company agreed to a binding arbitration proceeding with respect to such claims. In January 1996, the Company acquired all of the interests in three of the limited partnerships which were the subject of the arbitration in exchange for shares of and warrants to purchase shares of the Company's common stock. In an arbitration proceeding, if any liability is found to exist, the arbitrator would determine the amount of any damages, and may consider all distributions made to the partners, including the consideration received in the exchange offer, in determining the extent of damages, if any. However, there can be no assurance that an arbitrator would consider such factors in his or her determination of damages if the allegations are found to be true and damages are awarded. Based on the plaintiffs' failure to pursue the arbitration, the American Arbitration Association dismissed the case on November 25, 1998, but gave the plaintiffs until February 23, 1999, to obtain a court order compelling arbitration. To date, the plaintiffs have neither sought nor obtained such a court order. In the normal course of the Company's business, there are various other legal proceedings outstanding. In the opinion of management, these proceedings will not have a material adverse effect on the Company's financial statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS During the three month period ended December 31, 1998, 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 The Company's Common Stock is traded on the New York Stock Exchange ("NYSE") under the symbol "BNO." For the period represented below, the Company's Common Stock was traded on the NASDAQ Stock Market under the symbol "BNTN" until April 29, 1997, when the Company's Common Stock began trading on the NYSE. As of December 31, 1998, there were 29,576,844 shares of Common Stock outstanding held of record by approximately 1,064 stockholders. The following table sets forth the high and low sales prices for the Company's Common Stock reported on the NASDAQ from January 1, 1997 to April 28, 1997 and on the NYSE thereafter.
YEAR QUARTER HIGH LOW ---- ------- ---- --- 1997 First quarter $ 24.75 $ 14.63 Second quarter 17.13 12.63 Third quarter 19.25 13.50 Fourth quarter 21.88 11.25 1998 First quarter 13.69 9.75 Second quarter 13.50 7.38 Third quarter 10.75 4.69 Fourth quarter 6.25 2.44
On March 24, 1999, the last sales price for the Common Stock as reported by NYSE was $3.63 per share. The Company's policy is to retain its earnings to support the growth of the Company's business. Accordingly, the Board of Directors of the Company has never declared cash dividends on its Common Stock. The Company's indentures currently restrict the declaration and payment of any cash dividends. 24 24 ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA The following selected consolidated financial data for the Company for each of the five years in the period ended December 31, 1998, are derived from the Company's audited consolidated financial statements. The consolidated financial data below should be read in conjunction with the Company's Consolidated Financial Statements and related notes thereto and Item 7. -- Management's Discussion and Analysis of Financial Condition and Results of Operations contained elsewhere in this report.
YEARS ENDED DECEMBER 31, -------------------------------------------------------------------------- 1998 1997 1996 1995 (2) 1994 ------------ ------------ ------------ ------------ ------------ (amounts in thousands, except per share data) STATEMENT OF OPERATIONS: Total revenues $112,148 $179,019 $165,066 $ 65,068 $ 34,705 Lease operating costs and production taxes 44,675 41,887 24,518 10,703 9,531 Depletion, depreciation and amortization 35,638 47,592 34,525 17,411 10,298 Write-down and impairment of oil and gas properties 203,993 - - - - General and administrative expense 25,629 23,436 18,906 9,411 5,242 Interest expense 32,908 24,245 16,128 7,497 3,888 Partnership exchange expenses - - 2,140 - - Litigation settlement expenses - - - 1,673 - --------- ------- ------- ------- ------- Income (loss) before income taxes, minority interest and extraordinary charge (230,695) 41,859 68,849 18,373 5,746 Income tax expense (benefit) (24,220) 17,477 20,508 2,478 698 --------- ------- ------- ------- ------- Income (loss) before minority interest and extraordinary charge (206,475) 24,382 48,341 15,895 5,048 Minority interest (22,895) 6,333 9,984 5,304 2,094 --------- ------- ------- ------- ------- Income (loss) before extraordinary charge (183,580) 18,049 38,357 10,591 2,954 Extraordinary charge for early retirement of debt, net of tax benefit of $879 - - 10,075 - - --------- ------- ------- ------- ------- Net income (loss) $(183,580) $18,049 $28,282 $10,591 $ 2,954 ========= ======= ======= ======= ======= Net income (loss) per common share: Basic: Income (loss) before extraordinary charge $ (6.21) $ 0.62 $ 1.42 $ 0.42 $ 0.12 Extraordinary charge - - 0.38 - - --------- ------- ------- ------- ------- Net income (loss) $ (6.21) $ 0.62 $ 1.04 $ 0.42 $ 0.12 ========= ======= ======= ======= ======= Diluted: Income (loss) before extraordinary charge $ (6.21) $ 0.59 $ 1.29 $ 0.40 $ 0.12 Extraordinary charge - - 0.34 - - --------- ------- ------- ------- ------- Net income (loss) $ (6.21) $ 0.59 $ 0.95 $ 0.40 $ 0.12 ========= ======= ======= ======= ======= Weighted average common shares outstanding Basic 29,554 29,119 27,088 25,084 24,851 Diluted 29,554 30,834 29,813 26,673 25,325
25 25
AT DECEMBER 31, ----------------------------------------------------------------------------- 1998 1997 1996 1995 (2) 1994 ------------ ------------- ------------- ------------- ------------- BALANCE SHEET DATA: (amounts in thousands) Working capital (deficit) $ 55,864 $ 165,945 $ 98,417 $ (2,888) $ 21,785 Total assets 338,621 584,277 435,745 214,750 162,561 Long-term obligation, net of current portion 288,212 280,016 175,028 49,486 31,911 Stockholders' equity (1) 12,989 197,732 174,899 103,681 88,259
[FN] (1) No cash dividends were paid during any period presented. (2) The financial information related to Russia and included in the 1995 presentation contains information at, and for the nine months ended, September 30, 1995, the end of the fiscal period for GEOILBENT. 26 26 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL PRINCIPLES OF CONSOLIDATION AND ACCOUNTING METHODS The Company includes the results of operations of Benton-Vinccler in its consolidated financial statements and reflects the 20% ownership interest of Vinccler as a minority interest. Beginning in 1995, GEOILBENT has been included in the consolidated financial statements based on a fiscal period ending September 30. Results of operations for GEOILBENT reflect the twelve months ended September 30, 1996, 1997 and 1998. The Company's investment in GEOILBENT is proportionately consolidated based on the Company's ownership interest, and for oil and gas reserve information, the Company reports its 34% share of the reserves attributable to GEOILBENT. The Company uses the equity method of accounting for its investments in Severneftegaz. The Company follows the full-cost method of accounting for its investments in oil and gas properties. The Company capitalizes all acquisition, exploration, and development costs incurred. The Company accounts for its oil and gas properties using cost centers on a country by country basis. Proceeds from sales of oil and gas properties are credited to the full-cost pools. Capitalized costs of oil and gas properties are amortized within the cost centers on an overall unit-of-production method using proved oil and gas reserves as audited by independent petroleum engineers. Costs amortized 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 Notes to the Consolidated Financial Statements). Statement of Financial Accounting Standards No. 133 ("SFAS 133") establishes accounting and reporting standards for derivative instruments and hedging activities. This statement is effective for all fiscal quarters of all fiscal years beginning after June 15, 1999. The Company does not use derivative or hedging instruments. As a result, the Company does not believe the adoption of the standard will have a material effect on its results of operations or financial position. The following discussion of the results of operations and financial condition as of December 31, 1998 and 1997 and for each of the years in the three year period ended December 31, 1998, respectively, should be read in conjunction with the Company's Consolidated Financial Statements and related Notes thereto. RESULTS OF OPERATIONS The Company's results of operations for the year ended December 31, 1998, reflected the results for Benton-Vinccler, C.A. in Venezuela, which accounted for more than 90% of the Company's production and oil sales revenue. As a result of declines in world crude oil prices and lower production from the South Monagas Unit due to operational problems with certain high volume wells, oil sales in Venezuela were 45% lower in 1998 compared to 1997 with a 33% decrease in realized fees per barrel (from $10.01 in 1997 to $6.75 in 1998) and a 21% decrease in oil sales quantities (from 15,394,807 Bbls of oil in 1997 to 12,172,352 Bbls of oil in 1998). Additionally, the Company recognized full cost ceiling limitation write-downs of its oil and gas properties in Venezuela and Russia of $187.8 million and $10.1 million, respectively, and a $6.1 million impairment of capitalized costs associated with certain exploration activities. The Company also experienced increased interest expense as a result of the issuance of $115.0 million of senior unsecured notes in the fourth quarter of 1997. Benton-Vinccler also experienced increased operating expenses primarily in the areas of workovers, transportation and chemical costs, and increased capital requirements for production facilities. The increased costs resulted in increased per barrel lease operating costs and, especially when combined with the decreased fee realizations, represented a significantly higher percentage of oil sales revenues during the period than in the prior period. The following table presents selected expense items as a percentage of oil and gas sales:
1998 1997 1996 ------------ ------------ ------------- Lease Operating Costs and Production Taxes 49.5% 25.5% 16.6% Depletion, Depreciation and Amortization 39.5 29.0 23.4 General and Administrative 28.4 14.3 12.8 Interest 36.5 14.8 10.9
27 27 YEARS ENDED DECEMBER 31, 1998 AND 1997 The Company had revenues of $112.1 million for the year ended December 31, 1998. Expenses incurred during the period consisted of lease operating costs and production taxes of $44.7 million, depletion, depreciation and amortization expense of $35.6 million, write-down and impairment of oil and gas properties of $204.0 million, general and administrative expense of $25.6 million, interest expense of $32.9 million, income tax benefit of $24.2 million and minority interest reduction of $22.9 million. Net loss for the period was $183.6 million or $6.21 per share (diluted). By comparison, the Company had revenues of $179.0 million for the year ended December 31, 1997. Expenses incurred during the period consisted of lease operating costs and production taxes of $41.9 million, depletion, depreciation and amortization expense of $47.6 million, general and administrative expense of $23.4 million, interest expense of $24.2 million, income tax expense of $17.5 million, minority interest of $6.3 million. Net income for the period was $18.0 million or $0.59 per share (diluted). Revenues decreased $66.9 million, or 37%, during the year ended December 31, 1998 compared to the corresponding period of 1997 primarily due to decreased oil sales revenue in Venezuela as a result of declines in world crude oil prices and a 21% decrease in oil sales quantities due largely to operational problems with certain high volume wells. Sales quantities for the year ended December 31, 1998 from Venezuela and Russia were 12,172,352 Bbls and 923,602 Bbls, respectively, compared to 15,394,807 Bbls and 880,148 Bbls, respectively, for the year ended December 31, 1997. Prices for crude oil per Bbl averaged $6.75 (pursuant to terms of an operating service agreement) from Venezuela and $8.72 from Russia for the year ended December 31, 1998 compared to $10.01 and $11.28, respectively, for the year ended December 31, 1997. Foreign exchange gains were $5.5 million higher in 1998 compared to 1997 primarily due to the significant devaluation of the Russian Ruble during August and September of 1998. Lease operating costs and production taxes increased $2.8 million, or 7%, during the year ended December 31, 1998 compared to 1997 primarily due to continuing maturation of the Uracoa oil field in Venezuela resulting in higher water handling, gas handling, workover, transportation and chemical costs. The increase was partially offset by the devaluation of the Russian ruble, Russian legislation reducing penalties on late tax payments and reduced oil production in Venezuela. Depletion, depreciation and amortization decreased $12.0 million, or 25%, during the year ended December 31, 1998 compared to the corresponding period of 1997 primarily due to write-downs of oil and gas properties in Venezuela and Russia and reduced oil sales in Venezuela in 1998, partially offset by increased capital requirements in Venezuela. Depletion expense per BOE produced from Venezuela and Russia during the year ended December 31, 1998 was $2.62 and $2.68, respectively, compared to $2.83 and $3.50, respectively, during the previous year. Additionally, the Company recognized write-downs of oil and gas properties during 1998 in the Venezuela and Russia cost centers of $187.8 million and $10.1 million, respectively, 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 the Company for its Venezuelan and Russian oil sales. The Company also recognized $6.1 million of impairment expense associated with certain exploration activities. General and administrative expenses increased $2.2 million, or 9%, during the year ended December 31, 1998 compared to 1997 primarily due to an allowance for doubtful accounts related to amounts owed to the Company by its Chief Executive Officer (see Note 15 of Notes to the Consolidated Financial Statements) and costs incurred in the Company's China operation partially offset by decreased Venezuelan municipal taxes (which are a function of oil revenues). Interest expense increased $8.7 million, or 36%, in 1998 compared to 1997 primarily due to the issuance of $115 million in senior unsecured notes in November 1997. Income tax expense decreased $41.7 million, or 238%, during the year ended December 31, 1998 compared to 1997 primarily due to decreased taxable income in Venezuela as a result of write-downs of oil and gas properties. The net income attributable to the minority interest decreased $29.2 million, or 463%, for 1998 compared to 1997 as a result of the decreased profitability of Benton-Vinccler's operations in Venezuela. YEARS ENDED DECEMBER 31, 1997 AND 1996 The Company had revenues of $179.0 million for the year ended December 31, 1997. Expenses incurred during the period consisted of lease operating costs and production taxes of $41.9 million, depletion, depreciation and amortization expense of $47.6 million, general and administrative expense of $23.4 million, interest expense of $24.2 million, income tax expense of $17.5 million and minority interest of $6.3 million. Net income for the period was $18.0 million or $0.59 per share (diluted). By comparison, the Company had revenues of $165.1 million for the year ended December 31, 1996. Expenses incurred during the period consisted of lease operating costs and production taxes of $24.5 million, depletion, depreciation and amortization expense of $34.5 million, general and administrative expense of $18.9 million, interest expense of $16.1 million, partnership exchange expense of $2.1 million, income tax expense of $20.5 million, minority interest of $10.0 28 28 million and an extraordinary charge for early retirement of debt, net of tax benefit, of $10.1 million. Net income for the period was $28.3 million or $0.95 per share (diluted). Revenues increased $13.9 million, or 8%, during the year ended December 31, 1997 compared to the corresponding period of 1996 primarily due to increased oil sales in Venezuela and increased investment earnings partially offset by the gain on sale of properties in 1996. Sales quantities for the year ended December 31, 1997 from Venezuela and Russia were 15,394,807 Bbls and 880,148 Bbls, respectively, compared to 12,647,987 Bbls and 765,137 Bbls, respectively, for the year ended December 31, 1996. Prices for crude oil per Bbl averaged $10.01 (pursuant to terms of an operating service agreement) from Venezuela and $11.28 from Russia for the year ended December 31, 1997 compared to $10.82 and $11.82, respectively, for the year ended December 31, 1996. Revenues for 1997 were increased by a foreign exchange gain of $2.3 million compared to a gain of $2.8 million in 1996. Lease operating costs and production taxes increased $17.4 million, or 71%, during the year ended December 31, 1997 compared to 1996 primarily due to continued growth of the Company's Venezuelan operations, as well as the continuing maturation of the Uracoa oil field resulting in higher water handling, gas handling, workover, transportation and chemical costs. Depletion, depreciation and amortization increased $13.1 million, or 38%, during the year ended December 31, 1997 compared to the corresponding period in 1996. Depletion expense per BOE produced from Venezuela and Russia during the year ended December 31, 1997 was $2.83 and $3.50, respectively, compared to $2.33 and $3.59, respectively, during the previous year. General and administrative expenses increased $4.5 million, or 24% during the year ended December 31, 1997 compared to 1996 primarily due to the Company's increased corporate activity associated with the growth of the Company's business and increased Venezuelan municipal taxes (which are a function of growing oil revenues and increased tax rates). Interest expense increased $8.1 million, or 50%, in 1997 compared to 1996 primarily due to the issuance of $125 million in senior unsecured notes in May 1996 and to the issuance of $115 million in senior unsecured notes in November 1997. Income tax expense decreased $3.0 million, or 15%, during the year ended December 31, 1997 compared to 1996 primarily due to decreased taxable income in Venezuela. The net income attributable to the minority interest decreased $3.7 million, or 37%, for 1997 compared to 1996 as a result of the decreased profitability of Benton-Vinccler's operations in Venezuela. DOMESTIC OPERATIONS In March 1997, the Company acquired a 40% participation interest in three California State offshore oil and gas leases from Molino Energy Company, LLC ("Molino Energy"), which held 100% 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% participation interest in the leases, the Company became the operator of the project and paid 100% of the first $3.7 million and 53% 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. The Company's share of the drilling and testing of the 2199 #7 well was $8.5 million. In November 1998, the Company entered into an agreement to acquire Molino Energy's interest in the leases in exchange for the release of its joint interest billing obligations of approximately $1.9 million. The agreement to acquire Molino Energy's interest will be finalized upon the completion of certain lot splits and the assignment of various permits and rights. INTERNATIONAL OPERATIONS As a private contractor, Benton-Vinccler is subject to a statutory income tax rate of 34%. However, Benton-Vinccler reported significantly lower effective tax rates for 1996 and 1998 due to the effect of the devaluation of the Bolivar while Benton-Vinccler uses the U.S dollar as its functional currency, and further in 1998 due to a deferred tax asset valuation allowance. The Company cannot predict the timing or impact of future devaluations in Venezuela. A 3-D seismic survey has been conducted over the southwestern portion of the Delta Centro Block in Venezuela at an expected total cost to the Company of $8.3 million, of which $6.8 million had been spent though December 31, 1998. During the first quarter of 1999, drilling commenced on the Jarina-1 X, the first of the block's exploration wells, with a total anticipated cost to the Company of approximately $5.6 million. Subsequent seismic and drilling programs will be based on the results of the Jarina-1 X well. The Company's operations related to Delta Centro will be subject to oil and gas industry taxation, which currently provides for royalties of 16.66% and income taxes of 67.7%. GEOILBENT is subject to a statutory income tax rate of 35%. GEOILBENT has also been subject to various other tax burdens, including an oil export tariff which was terminated effective July 1, 1996. Excise, pipeline and other taxes (including a new oil export tariff introduced in 1999) continue to be levied on all oil producers and certain exporters. The Russian regulatory environment continues to be volatile and the Company is unable to predict the impact of taxes, duties and other burdens for the future. 29 29 In December 1996, the Company acquired Benton Offshore China Company, a privately held company headquartered in Denver, Colorado. Benton Offshore China Company's principal asset is a petroleum contract with CNOOC for an area known as Wan'An Bei, WAB-21. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for another one 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 also 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 the Company's 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, 1998, the Company has recorded no proved reserves attributable to this petroleum contract. In August 1997, the Company acquired the rights to a PSA with Jordan's NRA to explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan Block consists of approximately 1.2 million acres (4,827 square kilometers) and is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the terms of the PSA, the Company is obligated to make certain capital and operating expenditures in up to three phases over eight years. The Company is obligated to spend $5.1 million in the first exploration phase, which is expected to last approximately two years. If the Company ultimately elects to continue through phases two and three, it would be obligated to spend an additional $18 million over the succeeding six years. In October 1997, the Company signed a farmout agreement with Shell whereby the Company will acquire a 50% participation interest in Shell's Liaohe area onshore exploration project in northeast China. Shell holds a petroleum contract with China National Petroleum Corporation to explore and develop the deep rights in the Qingshui Block, a 563 square kilometer area (approximately 140,000 acres) in the delta of the Liaohe River. Shell will be the operator of the project. In July 1998, the Company paid to Shell 50% of Shell's prior investment in the Block, which was approximately $4 million ($2 million to the Company). The Company is required to pay 100% of the first $8 million of the costs for the phase one exploration period, after which any development costs will be shared equally. If a commercial well results from phase one and the Company elects to continue to phase two, then the Company will pay 100% of the first $8 million of the costs of the second phase of the exploration period, after which any development costs will be shared equally. If a commercial well does not result from phase one and the Company elects to continue to phase two, then the Company and Shell will share costs equally. The Company and Shell will share costs equally for the third exploration phase, if any. During the first quarter of 1999, drilling commenced on the Qing-22 Deep well as a part of the phase one exploration period activities. In December 1997, the Company signed a memorandum of understanding with Petrosen to receive a minimum 45% working interest in and to operate the approximately one-million acre onshore Thies Block in western Senegal. In addition, the Company obtained exclusive rights from Petrosen to evaluate and reprocess geophysical data for Senegal's shallow near-offshore acreage, an area encompassing approximately 7.5 million acres extending from the Mauritania border in the north to the Guinea Bissau border in the south. The Company may also choose certain blocks for further data acquisition and exploration drilling. The Company's working interest in any offshore discovery will be 85% with the remainder held by Petrosen. The Company's $5.4 million work commitment on the Thies Block, where Petrosen has recently drilled and completed the Gadiaga #2 discovery well, consists of hooking up the existing well, drilling two additional wells and constructing a 41-kilometer (approximately 25-mile) gas pipeline to Senegal's main electric generating facility near Dakar. The Company's minimum commitment related to the offshore blocks involves seismic reprocessing to be followed by additional data acquisition and drilling at the Company's discretion. In April 1998, the Company signed an agreement to earn a 40% equity interest in Severneftegaz. Severneftegaz 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 837,000 acres within and adjacent to the Urengoy field, Russia's largest producing natural gas field. Pursuant to a Cooperation Agreement between the Company and Severneftegaz, the Company will earn a 40% equity interest in exchange for providing the initial capital needed to achieve natural gas production. The Company's capital commitment will be in the form of a $100 million credit facility for the project, the terms of which have yet to be finalized, which is expected to be disbursed over the initial two-year development phase. The Company received voting shares representing a 40% ownership in Severneftegaz that contain restrictions on their sale and transfer. The 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 Severneftegaz, the Company has accounted for its interest in Severneftegaz using the equity method. Certain provisions of Russian corporate law would effectively require minority shareholder consent in the making of new agreements between the Company and Severneftegaz, or to the changing of any terms in any existing agreements, including the conditions upon which the restrictions on the shares could be removed, between the two such as the Cooperation Agreement and the Share Disposition Agreement. 30 30 EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION The Company's results of operations and cash flow are affected by changing oil and gas prices. However, the Company's Venezuelan revenues 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 the Company's Venezuelan revenues and cash flows. If the price of oil and gas increases, there could be an increase in the cost to the Company for drilling and related services because of increased demand, as well as an increase in revenues. Fluctuations in oil and gas prices may affect the Company's 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 made 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 Benton-Vinccler or the Company. Currently, there are no exchange controls in Venezuela or Russia that restrict conversion of local currency into U.S. dollars. Within the United States, inflation has had a minimal effect on the Company, but it is potentially an important factor in results of operations in Venezuela and Russia. With respect to Benton-Vinccler and GEOILBENT, substantially all of the sources of funds, including the proceeds from oil sales, the Company's 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, 1998, the Company realized net foreign exchange gains, primarily as a result of the decline in the value of the Venezuelan bolivar and the Russian ruble during periods when the Company's Venezuela-related subsidiaries and GEOILBENT had substantial net monetary liabilities denominated in bolivares and rubles. During the year ended December 31, 1998, the Company's net foreign exchange gains attributable to its Venezuelan and Russian operations were $1.7 million and $6.0 million, respectively. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, many of which are beyond the control of the Company. The Company has 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 to predict the extent to which the Company may be affected by future changes in exchange rates and exchange controls. The Company's operations are affected by political developments and laws and regulations in the areas in which it operates. In particular, oil and 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 gas wastes, or otherwise relating to the protection of the environment, may affect the Company's operations and results. CAPITAL RESOURCES AND LIQUIDITY The oil and gas industry is a highly capital intensive business. The Company requires capital principally to fund the following costs: (i) drilling and completion costs of wells and the cost of production and transportation facilities; (ii) geological, geophysical and seismic costs; and (iii) acquisition of interests in oil and gas properties. The amount of available capital will affect the scope of the Company's operations and the rate of its growth. The net funds raised and/or used in each of the operating, investing and financing activities for each of the years ended December 31, are summarized in the following table and discussed in further detail below:
YEARS ENDED DECEMBER 31, ---------------------------------------------- (IN THOUSANDS) 1998 1997 1996 ------------- ------------- ------------- Net cash provided by operating activities $ 8,561 $ 93,948 $ 84,852 Net cash used in investing activities (8,017) (216,028) (164,772) Net cash provided by financing activities 5,663 101,588 106,172 ------- --------- -------- Net increase (decrease) in cash $ 6,207 $ (20,492) $ 26,252 ======= ========= ========
At December 31, 1998, the Company had current assets of $92.8 million and current liabilities of $36.9 million, resulting in working capital of $55.9 million and current ratio of 2.51:1. This compares to the Company's working capital of 31 31 $165.9 million and a current ratio of 3.84:1 at December 31, 1997. The decrease of $110.0 million was due to expenditures related to the continuing development of the South Monagas Unit in Venezuela and reduced South Monagas oil sales revenues resulting from declines in world crude oil prices and reduced sales quantities. CASH FLOW FROM OPERATING ACTIVITIES. During 1998, 1997 and 1996, net cash provided by operating activities was approximately $8.6 million, $93.9 million and $84.9 million, respectively. Cash flow from operating activities decreased by $85.3 million in 1998 primarily due to decreased oil sales from Venezuela as a result of declines in world crude oil prices and reduced sales quantities. Cash flow from operating activities increased $9.0 million in 1997 primarily due to increased oil production in Venezuela. CASH FLOW FROM INVESTING ACTIVITIES. During 1998, 1997 and 1996, the Company had drilling and production related capital expenditures of approximately $120.0 million, $109.8 million and $95.5 million, respectively. Of the 1998 expenditures, $80.2 million was attributable to the development of the South Monagas Unit in Venezuela, $14.4 million related to the development of the North Gubkinskoye Field in Russia, $5.7 million related to the development of the Gaviota lease in Santa Barbara County, California, $4.2 million related to a 3-D seismic survey in the Delta Centro Block in Venezuela, $4.0 million related to the development of the Qingshui Block in China, $3.6 million related to the Samburg Block in Russia (in addition to $8.3 million loaned to Severneftegaz), $2.3 million related to the development of the Sirhan Block in Jordan and $5.6 million was attributable to other projects. In 1996, the Company also sold certain oil and gas properties for net proceeds of approximately $34.6 million. During 1998, the Company instituted a capital expenditure program which minimized expenditures to those that the Company believed were necessary in order to maintain current producing properties. This policy was instituted in response to the low market price for oil. The Company expects to continue limiting capital expenditures at this maintenance level until such time as world oil prices increase or sufficient funding from outside sources is available. The Company expects 1999 capital expenditures of approximately $45.0 million, including $7.1 million in expenditures by GEOILBENT in Russia, net to the Company's interest (which will be funded from borrowings under the EBRD Credit Facility, cash flow from operations or other financings). Additionally, the Company anticipates providing or arranging loans of up to $100 million over the next two years to Severneftegaz pursuant to an equity acquisition agreement signed in April 1998. The Company is currently evaluating funding alternatives for the loans to Severneftegaz. The Company's indentures contain provisions that restrict the manner in which the Company can invest in certain of its current operations including GEOILBENT. The Company continually assesses its 1999 capital expenditure program in view of its financial resources and of industry and commodity price changes. Its total 1999 capital expenditure requirements include approximately $10-15 million at South Monagas Unit, $10-12 million for well commitments in China and at Delta Centro, and $7-10 million for Severneftegaz. The Company anticipates that Geoilbent will continue to fund itself through its own cash flows and credit facilities. The Company's remaining capital commitments worldwide are relatively minimal and for the most part are substantially at the Company's discretion. The timing and size of the 1999 investments for Severneftegaz are also substantially under the Company's discretion. The Company believes it has or can obtain sufficient funding for certain of its expected capital requirements from working capital and cash flow from operations. The Company's future financial condition and results of operations will largely depend upon prices received for its oil production and the costs of acquiring, finding, developing and producing reserves. Prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond the Company's control. If oil prices continue at current levels or decline moderately, and if oil production continues at expected levels, the Company believes that its current cash and cash provided by operating activities will be sufficient to meet the Company's liquidity needs for routine operations and to service its outstanding debt through 1999. The Company continues to evaluate and review strategic alternatives and has engaged J.P. Morgan Securities, Inc. to advise the Company related to these alternatives. In the event that future cash requirements are greater than the Company's financial resources, the Company intends to pursue strategic joint ventures or alliances with other industry partners, sell property interests, merge or combine with another entity, or issue debt or equity securities. CASH FLOW FROM FINANCING ACTIVITIES. In May 1996, the Company issued $125 million in 11.625% senior unsecured notes due May 1, 2003. In November 1997, the Company issued $115 million in 9.375% senior unsecured notes due November 1, 2007, of which the Company subsequently repurchased $10 million at their par value. Interest on 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, 1998, the Company was in compliance with all covenants of the indentures. 32 32 The EBRD and IMB have agreed to lend a total of $65 million to GEOILBENT (owned 34% by the Company) under parallel reserve-based loan agreements. As of December 31, 1998, GEOILBENT had borrowed $19 million and in March 1999, GEOILBENT borrowed an additional $8.3 million under these agreements. The proceeds from the loans are being used by GEOILBENT to develop the North Gubkinskoye Field in West Siberia, Russia. Additional borrowings will be based on achieving certain reserve and production milestones. YEAR 2000 COMPLIANCE The Year 2000 problem concerns the inability of information systems to properly recognize and process date-sensitive information beyond January 1, 2000. The Company began a process of assessing its information technology systems in November 1997 and has to date not uncovered any significant Year 2000 deficiencies. Substantially all of the software utilized by the Company is purchased or licensed from external providers. The Company's home office business systems are Year 2000 compliant. Its subsidiaries are currently in the process of upgrading their business systems, with completion anticipated during the second quarter of 1999 in Venezuela and the third quarter of 1999 in Russia. A review of the Company's non-financial software and imbedded chip technology is currently underway to assess the impact of the Year 2000 on systems such as plant flow control devices, product measurement and delivery devices and fire or other disaster-related safety systems. To date, the costs associated with required modifications to become Year 2000 compliant have not exceeded $100,000, and the Company does not anticipate that the cost of converting any non-compliant systems will be material to its financial condition. The Company anticipates the completion of the process of obtaining Year 2000 compliance information from its material suppliers and customers by April 30, 1999. To the extent that the Company does not receive adequate responses from its material third-party suppliers and customers by April 30, 1999, it is prepared to develop contingency plans that would include changing suppliers and customers to those who have demonstrated Year 2000 readiness. However, there can be no assurance that the Company will be successful in finding such alternative suppliers and customers. The oil produced in Venezuela by the Company, which is delivered to PDVSA under the terms of an operating service agreement lasting until 2012, represented approximately 91% of the Company's oil sales during 1998. In the event that PDVSA is unable to accept deliveries of, or make payment for, the oil produced by the Company due to a Year 2000 failure, the Company's operations and financial position could be materially and adversely affected. The failure to correct a material Year 2000 problem could result in an interruption in, or a failure of, certain normal business activities or operations. Such failures could materially and adversely affect the Company's results of operations, liquidity and financial condition. Due to the general uncertainty inherent in the Year 2000 problem, resulting in part from the uncertainty of the Year 2000 readiness of third-party suppliers and customers, the Company is unable to determine at this time whether the consequences of Year 2000 failures will have a material impact on the Company's results of operations, liquidity or financial condition. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to market risk from adverse changes in oil and gas prices, interest rates and foreign exchange, as discussed below. OIL AND GAS PRICES As an independent oil and gas producer, the Company's revenue and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and condensate. The Company currently neither produces nor records reserves related to natural gas. 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 the control of the Company. Historically, prices received for oil and gas production have been volatile and unpredictable, and such volatility is expected to continue. Average realizations per barrel have declined from $10.07 in 1997 to $6.89 in 1998. From time to time, the Company has utilized hedging transactions with respect to a portion of its oil and gas production to achieve a more predictable cash flow, as well as to reduce its exposure to price fluctuations, but the Company has utilized no such transactions since 1996, and does not expect to utilize such transactions in the near future. 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 and gas revenues when the hedged production is delivered, such gains and losses are generally offset by similar changes in the realized prices of the commodities. The Company did not enter into any commodity hedging agreements during 1997 and 1998. 33 33 INTEREST RATES Total long term debt of $288.2 million at December 31, 1998, included $230 million of fixed-rate senior unsecured notes maturing in 2003 ($125 million) and 2007 ($105 million). Another $51.6 million of debt is attributable to floating-rate back-to-back loan facilities wherein Benton-Vinccler and GEOILBENT pay floating-rate interest to a bank, which then pays to the Company interest on cash collateral deposited by the Company to support the loans, such interest to the Company being equal to the floating rate payment less 0.375% for Benton- Vinccler and less 0.25% for GEOILBENT, thereby mitigating the floating-rate interest rate risk of such debt. The balance of $6.4 million (2% of total long term debt), consisting primarily of the Company's share of debt owed by Geoilbent, is subject to the market volatility of floating rates. A hypothetical 10% adverse change in the floating rate would not have had a material affect on the Company's results of operations for the fiscal year ended December 31, 1998. FOREIGN EXCHANGE The Company's operations are located primarily outside of the United States. In particular, the Company's 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, revenues are received under a contract in effect through 2012 in US dollars; expenditures are both in US dollars and local currency. For the Russian operations, revenues are received primarily in US dollars, with less than 15% of such revenues being received in local currency; expenditures are both in US dollars and local currency, although a larger percentage of the expenditures were in local currency. The Company has utilized no currency hedging programs to mitigate any risks associated with operations in these countries, and therefore the Company's 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-29. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE No information is required to be reported under this item. 34 34 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 * [FN] * 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 the Company's Proxy Statement for the 1999 Annual Meeting of Stockholders. 35 35 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, 1998 and 1997 ...............................S-3 Consolidated Statements of Operations for the Years Ended December 31, 1998, 1997 and 1996 ........................................................S-4 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1998, 1997 and 1996 ............................................S-5 Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996 ........................................................S-6 Notes to Consolidated Financial Statements...............................................S-8
2. Consolidated Financial Statement Schedules: Schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable, or the information is included in the footnotes to the financial statements. 3. Exhibits: 3.1. Certificate of Incorporation of the Company filed September 9, 1988 (Incorporated by reference to Exhibit 3.1 to the Company's Registration Statement (Registration No. 33-26333). 3.2 Amendment to Certificate of Incorporation of the Company filed June 7, 1991 (Previously filed as an exhibit to the Company's S-1 Registration Statement (Registration No. 33-39214)). 3.3 Restated Bylaws of the Company (Incorporated by reference to Exhibit 3.3 to the Company's Form 10-K for the year ended December 31, 1996). 4.1 Form of Common Stock Certificate (Previously filed as an exhibit to the Company's S-1 Registration Statement (Registration No. 33-26333)). 10.4 Form of Employment Agreements (Exhibit 10.19) (Previously filed as an exhibit to the Company's 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 the Company's 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 the Company's 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 the Company's S-1 Registration Statement (Registration No. 33-46077)).
36 36 10.10 Operating Service Agreement between the Company 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 the Company's 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% Senior Notes Due 2003 (Incorporated by reference to Exhibit 4.1 to the Company's 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% Senior Notes due 2007 (Incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q for the quarter ended September 30, 1997). 21.1 List of subsidiaries. 23.1 Consent of PricewaterhouseCoopers LLP. 23.2 Consent of Deloitte & Touche LLP. 23.3 Consent of Huddleston & Co., Inc. 27.1 Financial Data Schedule.
[FN] (b) Reports on Form 8-K No Form 8-K was filed during the last quarter of the registrant's fiscal year. 37 37 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Benton Oil and Gas Company In our opinion, the accompanying consolidated balance sheet as of December 31, 1998 and the related consolidated statements of operations, stockholders' equity and cash flows present fairly, in all material respects, the financial position of Benton Oil and Gas Company and its subsidiaries (the "Company") at December 31, 1998, and the results of their operations and their cash flows for the year then ended, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with generally accepted auditing standards 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 audit provides a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP San Francisco, California March 25, 1999 S-1 38 38 INDEPENDENT AUDITORS' REPORT - ---------------------------- Board of Directors and Stockholders Benton Oil and Gas Company Carpinteria, California We have audited the accompanying consolidated balance sheet of Benton Oil and Gas Company and subsidiaries as of December 31, 1997, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the two years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Benton Oil and Gas Company and subsidiaries at December 31, 1997 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Los Angeles, California March 24, 1998 S-2 39 39 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands)
DECEMBER 31, ------------------------------- 1998 1997 ------------- ------------- ASSETS - ------ CURRENT ASSETS: Cash and cash equivalents $ 18,147 $ 11,940 Restricted cash 12 48 Marketable securities 41,173 156,436 Accounts and notes receivable: Accrued oil and gas revenue 17,307 45,379 Joint interest and other, net 12,482 8,029 Prepaid expenses and other 3,688 2,463 -------- ------- TOTAL CURRENT ASSETS 92,809 224,295 RESTRICTED CASH 65,670 74,288 OTHER ASSETS 11,725 12,497 DEFERRED INCOME TAXES 2,976 - INVESTMENT IN AND ADVANCES TO AFFILIATED COMPANY 11,975 - PROPERTY AND EQUIPMENT: Oil and gas properties (full cost method - costs of $35,228 and $31,588 excluded from amortization in 1998 and 1997, respectively) 483,494 367,756 Furniture and fixtures 9,608 5,734 -------- -------- 493,102 373,490 Accumulated depletion, impairment and depreciation (339,636) (100,293) -------- -------- 153,466 273,197 -------- -------- $338,621 $584,277 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY - ------------------------------------ CURRENT LIABILITIES: Accounts payable, trade and other $ 10,014 $ 27,567 Accrued interest payable 5,527 5,533 Accrued expenses 19,342 17,722 Income taxes payable 1,847 4,535 Short term borrowings - 1,530 Current portion of long term debt 215 1,463 -------- ------- TOTAL CURRENT LIABILITIES 36,945 58,350 DEFERRED INCOME TAXES - 24,811 LONG TERM DEBT 288,212 280,016 COMMITMENTS AND CONTINGENCIES MINORITY INTEREST 475 23,368 STOCKHOLDERS' EQUITY Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none Common stock, par value $0.01 a share; Authorized 80,000 shares and 40,000 shares at December 31, 1998 and 1997, respectively; issued 29,627 and 29,522 shares at December 31, 1998 and 1997, respectively 296 295 Additional paid-in capital 147,054 146,125 Retained earnings (deficit) (131,569) 52,011 Treasury stock, at cost, 50 shares (699) (699) Employee note receivable, net (2,093) - ------- ------ TOTAL STOCKHOLDERS' EQUITY 12,989 197,732 -------- ------- $338,621 $584,277 ======== ========
See accompanying notes to consolidated financial statements. S-3 40 40 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data)
YEARS ENDED DECEMBER 31, ----------------------------------------------- 1998 1997 1996 ------------ ------------ ------------ REVENUES Oil and gas sales $ 90,271 $ 163,957 $ 147,703 Gain on sale of properties - - 7,175 Net gain on exchange rates 7,757 2,285 2,820 Investment earnings and other 14,120 12,777 7,368 --------- --------- --------- 112,148 179,019 165,066 --------- --------- --------- EXPENSES Lease operating costs and production taxes 44,675 41,887 24,518 Depletion, depreciation and amortization 35,638 47,592 34,525 Write-down and impairment of oil and gas properties 203,993 - - General and administrative 25,629 23,436 18,906 Interest 32,908 24,245 16,128 Partnership exchange expenses - - 2,140 --------- --------- --------- 342,843 137,160 96,217 --------- --------- --------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST (230,695) 41,859 68,849 INCOME TAX EXPENSE (BENEFIT) (24,220) 17,477 20,508 --------- --------- --------- INCOME (LOSS) BEFORE MINORITY INTEREST (206,475) 24,382 48,341 MINORITY INTEREST (22,895) 6,333 9,984 --------- --------- --------- INCOME (LOSS) BEFORE EXTRAORDINARY CHARGE (183,580) 18,049 38,357 EXTRAORDINARY CHARGE FOR EARLY RETIREMENT OF DEBT, NET OF TAX BENEFIT OF $879 - - 10,075 --------- --------- --------- NET INCOME (LOSS) $(183,580) $ 18,049 $ 28,282 ========= ========= ========= NET INCOME (LOSS) PER COMMON SHARE: Basic: Income (loss) before extraordinary charge $ (6.21) $ 0.62 $ 1.42 Extraordinary charge - - 0.38 --------- ------- ------- Net Income (loss) $ (6.21) $ 0.62 $ 1.04 ========= ======= ======= Diluted: Income (loss) before extraordinary charge $ (6.21) $ 0.59 $ 1.29 Extraordinary charge - - 0.34 --------- ------- ------- Net Income (loss) $ (6.21) $ 0.59 $ 0.95 ========= ======= =======
See accompanying notes to consolidated financial statements. S-4 41 41 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (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, 1996 25,509 $ 255 $ 97,746 $ 5,680 - - $103,681 Issuance of common shares: Exercise of warrants 994 10 12,134 - - - 12,144 Exercise of stock options 888 9 5,941 - - - 5,950 Conversion of notes and debentures 711 7 6,870 - - - 6,877 Acquisitions 796 8 18,574 - - - 18,582 Securities registration costs - - (617) - - - (617) Net income - - - 28,282 - - 28,282 ------ ----- --------- --------- ----- ------- ------- BALANCE AT DECEMBER 31, 1996 28,898 289 140,648 33,962 - - 174,899 Issuance of common shares: Exercise of warrants 343 3 3,524 - - - 3,527 Exercise of stock options 281 3 1,953 - - - 1,956 Treasury stock (50 shares) - - - - $(699) - (699) Net income - - - 18,049 - - 18,049 ------ ----- --------- --------- ----- ------- ------- BALANCE AT DECEMBER 31, 1997 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 ====== ===== ========= ========= ===== ======= =======
See accompanying notes to consolidated financial statements. S-5 42 42 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
YEARS ENDED DECEMBER 31, -------------------------------------------- 1998 1997 1996 ----------- ------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $(183,580) $ 18,049 $ 28,282 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation and amortization 35,638 47,592 34,525 Write-down and impairment of oil and gas properties 203,993 - - Amortization of financing costs 1,442 1,390 670 (Gain) loss on disposition of assets 74 11 (6,950) Partnership exchange expenses - - 2,140 Allowance for employee notes and accounts receivable 2,900 31 336 Minority interest in undistributed earnings (losses) of subsidiary (22,893) 6,336 9,984 Extraordinary charge for early retirement of debt 10,075 Deferred income taxes (27,787) 8,132 16,679 Changes in operating assets and liabilities: Accounts and notes receivable 18,626 6,558 (35,516) Prepaid expenses and other (1,225) (872) (1,377) Accounts payable (17,553) 5,196 2,022 Accrued interest payable (6) 1,757 2,915 Accrued expenses 1,620 (3,878) 20,342 Income taxes payable (2,688) 3,646 725 -------- -------- -------- NET CASH PROVIDED BY OPERATING ACTIVITIES 8,561 93,948 84,852 -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sale of property and equipment - - 34,638 Additions of property and equipment (119,959) (109,760) (95,497) Investment in and advances to affiliated company (11,975) - - Increase in restricted cash (230) (13,436) (74,050) Decrease in restricted cash 8,884 11,600 21,864 Purchases of marketable securities (55,438) (291,943) (133,296) Maturities of marketable securities 170,701 187,511 81,292 Distributions from limited partnerships - - 277 -------- -------- -------- NET CASH USED IN INVESTING ACTIVITIES (8,017) (216,028) (164,772) -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from exercise of stock options and warrants 930 5,483 17,818 Purchase of treasury stock - (699) - Proceeds from issuance of short term borrowings and notes payable 8,093 116,190 181,921 Payments on short term borrowings and notes payable (2,675) (11,680) (76,469) Prepayment premiums on debt retirement - - (10,632) Increase in other assets (685) (7,706) (6,466) -------- -------- -------- NET CASH PROVIDED BY FINANCING ACTIVITIES 5,663 101,588 106,172 -------- -------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 6,207 (20,492) 26,252 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 11,940 32,432 6,180 -------- -------- -------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 18,147 $ 11,940 $ 32,432 ======== ======== ======== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during the year for interest expense $ 31,032 $ 20,860 $ 13,519 ======== ======== ======== Cash paid during the year for income taxes $ 3,349 $ 4,589 $ 3,287 ======== ======== ========
See accompanying notes to consolidated financial statements. S-6 43 43 SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: During the year ended December 31, 1998, the Company reduced stockholders' equity by $2.1 million, the portion of the note receivable from its Chief Executive Officer secured by the Company's stock and stock options. (see Note 15). During the year ended December 31, 1997, certain trade payables of GEOILBENT were converted to long term debt. The Company's proportionate share of the converted payables is $1.5 million. During the year ended December 31, 1996, the Company acquired Benton Offshore China Company, formerly Crestone Energy Corporation, a privately held corporation headquartered in Denver, Colorado, for 628,142 shares of common stock and options to purchase 107,571 shares of the Company's common stock at $7.00 per share, valued in total at $14.6 million. During the year ended December 31, 1996, $3.2 million principal amount of the Company's 8% convertible notes and $4.3 million principal amount of the Company's 8% convertible debentures were retired upon conversion into 275,081 and 435,872 shares of the Company's common stock, respectively. During the year ended December 31, 1996, the Company financed the purchase of oil and gas equipment and services in the amount of $0.3 million. During the year ended December 31, 1996, the Company acquired the partners' interests in each of the three limited partnerships sponsored by the Company in exchange for an aggregate of 168,362 shares of the Company's common stock and warrants to purchase 587,783 shares of common stock at $11.00 per share, with a total value of $4.0 million. See accompanying notes to consolidated financial statements. S-7 44 44 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION Benton Oil and Gas Company (the "Company") engages in the exploration, development, production and management of oil and gas properties. The Company conducts its business in Venezuela, Russia, the United States, China, Jordan and Senegal. The Company and its former subsidiary, Benton Oil and Gas Company of Louisiana, participated as the managing general partner of three oil and gas limited partnerships formed during 1989 through 1991. Under the provisions of the limited partnership agreements, the Company received compensation as stipulated therein, and functioned as an agent for the partnerships to arrange for the management, drilling, and operation of properties, and assumed customary contingent liabilities for partnership obligations. In January 1996, the Company acquired the limited partnership interests for an aggregate of 168,362 shares of common stock and warrants to purchase 587,783 shares of common stock at $11 per share, and liquidated the partnerships (see Note 2). The consolidated financial statements include the accounts of the Company and its subsidiaries. The Company's investment in GEOILBENT, its Russian joint venture, is accounted for using proportionate consolidation based on the Company's ownership interest. The Company's investment in Severneftegaz, a Russian open joint stock company, is accounted for using the equity method because of the significant influence the Company exercises over its operations and management. All intercompany profits, transactions and balances have been eliminated. The Company accounts for its investment in GEOILBENT and Severneftegaz based on a fiscal year ending September 30. The consolidated financial statements have been adjusted to reflect the Company's capital contribution of $2.0 million made to GEOILBENT in December 1998. During 1998, the Company instituted a capital expenditure program which minimized expenditures to those that the Company believed were necessary in order to maintain current producing properties. The Company's future financial condition and results of operations will largely depend upon prices received for its oil production and the costs of acquiring, finding, developing and producing reserves. Prices for oil are subject to fluctuation in response to change in supply, market uncertainty and a variety of factors beyond the Company's control. The Company believes its current cash and cash to be provided by operating activities will be sufficient to meet the Company's liquidity needs for routine operations and to service its outstanding debt through 1999. The Company continues to evaluate and review strategic alternatives and has engaged J.P. Morgan Securities, Inc. to advise the Company related to these alternatives. If market conditions worsen and future cash requirements are greater than the Company's financial resources, the Company intends to pursue strategic joint ventures or alliances with other industry partners, sell property interests, merge or combine with another entity, or issue debt or equity securities. REVENUE RECOGNITION Oil and 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 agreements and is classified as current or non-current based on the terms of the agreements. S-8 45 45 MARKETABLE SECURITIES Marketable securities are carried at amortized cost. The marketable securities the Company may purchase are limited to those defined as Cash Equivalents in the indentures for its 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. The Company's marketable securities at cost, which approximates fair value, at December 31, 1998, consisted of $41.2 million in commercial paper and at December 31, 1997, consisted of $12.6 million in government backed notes, $139.4 million in commercial paper, $2.4 million in agreements to repurchase treasury securities and $2.0 million in bankers' acceptances. ACCOUNTS AND NOTES RECEIVABLE The Company has recorded an allowance for doubtful accounts of $3.2 million and $0.3 million related to employee notes and accounts receivable and other accounts receivable at December 31, 1998 and 1997, respectively (see Note 15). 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. PROPERTY AND EQUIPMENT The Company follows 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 gas reserves are capitalized as incurred, including exploration overhead of $2.4 million, $1.9 million and $1.4 million for the years ended December 31, 1998, 1997 and 1996, 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. The Company regularly evaluates its unproved properties on a country by country basis for possible impairment. If the Company abandons all exploration efforts in a country where no proved reserves are assigned, all exploration and acquisition costs associated with the country are expensed. During 1998, the Company recognized $6.1 million 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. The principal portion of such costs, excluding those related to the acquisition of Benton Offshore China Company, is 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. Excluded costs at December 31, 1998 consisted of the following by year incurred (in thousands):
TOTAL 1998 1997 1996 PRIOR TO 1996 ----- ---- ---- ---- ------------- Property acquisition costs $ 15,106 - - $ 15,106 - Exploration costs 20,122 14,629 4,181 496 816 -------- -------- ------- -------- -------- $ 35,228 $ 14,629 $ 4,181 $ 15,602 $ 816 ======== ======== ======= ======== ========
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 attributable to the Venezuelan cost center for the years ended December 31, 1998, 1997 and 1996 was $31.8 million, $43.6 million and $29.5 million ($2.62, $2.83 and $2.33 per equivalent barrel), respectively. Depletion expense attributable to the Russian cost center for the years ended December 31, 1998, 1997 and 1996 was $2.5 million, $3.1 million and $2.7 million ($2.68, $3.50 and $3.59 per equivalent barrel), respectively. Depletion expense attributable to the United States cost center for the year ended December 31, 1996 was $1.7 million ($6.55 per equivalent barrel). S-9 46 46 A gain or loss is recognized on sales 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 $1.3 million, $0.9 million and $0.5 million for the years ended December 31, 1998, 1997 and 1996, respectively. The major components of property and equipment at December 31 are as follows (in thousands):
1998 1997 ---- ---- Proved property costs $438,972 $331,645 Costs excluded from amortization 35,228 31,588 Oilfield inventories 9,294 4,523 Furniture and fixtures 9,608 5,734 -------- -------- 493,102 373,490 Accumulated depletion, impairment and depreciation (339,636) (100,293) ======== ======== $153,466 $273,197 ======== ========
The Company performs a quarterly cost center ceiling test of its oil and gas properties under the full cost accounting rules of the Security 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 and Russia cost centers of $187.8 million and $10.1 million, respectively. 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 The Company has significant operations outside of the United States, principally in Russia and Venezuela. Both Russia and Venezuela are considered highly inflationary economies. As a result, operations in those countries are remeasured in United States dollars, and all currency gains or losses are recorded in the statement of income. The Company attempts to manage its operations in a manner to reduce its 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 the influence of the Company. The Company has 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 the Company may be affected by future changes in exchange rates. FINANCIAL INSTRUMENTS The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities and accounts receivable. The Company's short term investments are placed with a wide array of financial institutions with high credit ratings. This diversified investment policy limits the Company's exposure both to credit risk and to concentrations of credit risk. Accounts receivable result from oil and gas exploration and production activities. A majority of the Company's customers and partners are engaged in the oil and gas business. One customer purchased 91%, 94% and 93% of the Company's oil production during the years ended December 31, 1998, 1997 and 1996, respectively. Although the Company does not currently foresee a credit risk associated with these receivables, repayment is dependent upon the financial stability of the customer. S-10 47 47 The Company's 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 carrying values of the Company's long term debt, except for the senior unsecured notes, are considered to approximate their fair values because their interest rates are comparable to current rates available to the Company. The aggregate fair value of the Company's senior unsecured notes, based on the last trading prices at December 31, 1998 and 1997, was approximately $149.9 million and $246.7 million, respectively. TREASURY STOCK In June 1997, the Board of Directors instituted a treasury stock repurchase program under which the Company is authorized to purchase up to 1,500,000 shares of its common stock. The shares will be used for re-issuance in connection with the Company's employee stock option plan, treasury stock or for other corporate purposes to be determined in the future. During 1997, the Company 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. This requirement is effective for the Company in 1998. However, the Company did not have any items of other comprehensive income during the three years ended December 31, 1998 and, in accordance with SFAS 130, has not provided a separate statement of comprehensive income. OPERATING SEGMENTS Statement of Financial Accounting Standards No. 131 ("SFAS 131") requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the Company's chief operating decision makers in deciding how to allocate resources and in assessing performance. This requirement is effective for the Company in 1998 (see Note 8). MINORITY INTERESTS The Company records a minority interest attributable to the minority shareholders of its subsidiaries. The minority interests in net income and losses are subtracted or added to arrive at consolidated net income. During 1998, losses attributable to the minority shareholders of Benton-Vinccler, a subsidiary owned 80% by the Company, exceeded their interest in equity capital. Accordingly, $3.5 million of Benton-Vinccler's 1998 loss attributable to the minority shareholders has been included in the consolidated net loss of the Company. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles 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 1997 and 1996 have been reclassified to conform to the 1998 financial statement presentation. S-11 48 48 NOTE 2 - ACQUISITIONS AND SALES In April 1996, the Company sold its remaining interests in the West Cote Blanche Bay, Rabbit Island and Belle Isle Fields located in the Gulf Coast of Louisiana for approximately $35.4 million, resulting in a gain of approximately $7.2 million after adjustments for revenues and expenses subsequent to the effective date of December 31, 1995 and satisfaction of a net profits interest associated with the properties. In conjunction with this sale and to obtain the required consents for such sale, the Company agreed to repay $35 million in senior unsecured notes and a $5 million revolving credit facility which was secured in part by these properties. Debt prepayment premiums and related costs totaling approximately $11.0 million ($10.1 million net of tax benefits) were recognized as an extraordinary charge in 1996. In January 1996, the Company completed an exchange offer under which it issued an aggregate of 168,362 shares of common stock and warrants to purchase 587,783 shares of common stock at $11 per share in exchange for all outstanding limited partnership interests in the three remaining limited partnerships sponsored by the Company. The shares of common stock were valued at $1.9 million (based upon the current market price at the time of the offer), which was allocated to oil and gas properties. Substantially all of the oil and gas properties were immediately sold at their approximate book value. The warrants, issued as an inducement to the participants to accept the exchange offer, were valued at $3.64 per warrant (an aggregate of $2.1 million), which was charged to expense in 1996. NOTE 3 - LONG TERM DEBT Long term debt consists of the following at December 31 (in thousands):
1998 1997 ---- ---- Senior unsecured notes with interest at 9.375%. See description below. $ 105,000 $ 105,000 Senior unsecured notes with interest at 11.625%. See description below. 125,000 125,000 Benton-Vinccler credit facility with interest at LIBOR plus 6.125%. Collateralized by a time deposit of the Company earning approximately LIBOR plus 5.75%. See description below. 50,000 50,000 Reserve-based loans with average interest rate of LIBOR plus 5.25%. See description below. 6,453 - GEOILBENT credit facility collateralized by a time deposit of the Company earning approximately 5.6%. See description below. 1,624 - Other 350 1,479 --------- --------- 288,427 281,479 Less current portion 215 1,463 --------- --------- $ 288,212 $ 280,016 ========= =========
In November 1997, the Company issued $115 million in 9.375% senior unsecured notes due November 1, 2007, of which the Company subsequently repurchased $10 million at their par value. In May 1996, the Company issued $125 million in 11.625% senior unsecured notes due May 1, 2003. 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, 1998, the Company was 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 the Company. The credit facility is collateralized in full by a time deposit of the Company, bears interest at LIBOR plus 6.125% and matures in August 2001. The Company receives interest on its time deposit and a security fee on the outstanding principal of the loan, for a combined total of approximately LIBOR plus 5.75%. The loan arrangement contains no restrictive covenants and no financial ratio covenants. GEOILBENT (owned 34% by the Company) has borrowed $19.0 million under parallel reserve-based loan agreements with the European Bank for Reconstruction and Development ("EBRD") and International Moscow Bank ("IMB"). EBRD and IMB have agreed to lend up to a total of $65 million to GEOILBENT based on achieving certain reserve and production milestones. Under these loan agreements, the Company and other shareholders of GEOILBENT have significant support obligations. Each shareholder shall be jointly and severally liable to EBRD and IMB for any losses, damages, liabilities, S-12 49 49 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 LIBOR plus 5.25% payable on January 27 and July 27 each year. Principal payments will be due in varying installments every six months beginning January 27, 2000 until 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. The Company's share of the amounts borrowed under the loan agreements was $6.5 million at December 31, 1998. In October 1995, GEOILBENT entered into an agreement with Morgan Guaranty for a credit facility under which the Company provides 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%, subject to certain adjustments, or the Morgan Guaranty prime rate plus 2%, whichever is selected at the time a loan is made. At December 31, 1997, the Company's proportionate share of the outstanding borrowings was $1.5 million and was classified as short term. In conjunction with GEOILBENT's reserve-based loan agreements with the EBRD and IMB, repayment of the credit facility was subordinated to payments due to the EBRD and IMB and, accordingly, the credit facility was reclassified as long term in 1998. The credit facility contains no restrictive covenants and no financial ratio covenants. The principal payment requirements for the long term debt outstanding at December 31, 1998 are as follows for the years ending December 31 (in thousands): 1999 $ 215 2000 136 2001 50,000 2002 993 2003 126,720 Subsequent Years 110,363 --------- $ 288,427 =========
NOTE 4 - COMMITMENTS AND CONTINGENCIES On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the United States Bankruptcy Court, Western District of Louisiana against the Company 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 date has been scheduled for August 9, 1999 and discovery is ongoing, but incomplete. The Company intends to vigorously contest the suit, and in management's opinion it is too early to assess the probability of an unfavorable outcome. In the normal course of its business, the Company may periodically become subject to actions threatened or brought by its investors or partners in connection with the operation or development of its properties or the sale of securities. Prior to 1992, the Company was engaged in the formation and operation of oil and gas limited partnership interests. In 1992, the Company ceased raising funds through such sales. Certain limited partners in limited partnerships sponsored by the Company have brought an action against the Company in connection with the Company's operation of the limited partnerships as managing general partner. The plaintiffs seek actual and punitive damages for alleged actions and omissions by the Company in operating the partnerships and alleged misrepresentations made by the Company in selling the limited partnership interests. In May 1995, the Company agreed to a binding arbitration proceeding with respect to such claims. Based on the plaintiffs' failure to pursue the arbitration, the American Arbitration Association dismissed the case on November 25, 1998, but gave the plaintiffs until February 23, 1999, to obtain a court order compelling arbitration. To date, the plaintiffs have neither sought nor obtained such a court order. The Company is also subject to ordinary litigation that is incidental to its business, none of which are expected to have a material adverse effect on the Company's financial statements. In May 1996, the Company entered into an agreement with Morgan Guaranty which provided for an $18 million cash collateralized 5-year letter of credit to secure the Company's performance of the minimum exploration work program required in the Delta Centro Block in Venezuela. In December 1998, the letter of credit was reduced to $11.2 million as a result of expenditures made related to the exploration work program. S-13 50 50 The Company has employment contracts with 4 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 July 10, 1999 to June 1, 2001. The Company has also entered into employment agreements with 8 individuals, which provide for certain severance payments in the event of a change of control of the Company and subsequent termination by the employees for good reason. The Company has also entered into various exploration and development contracts in various countries which require minimum expenditures, some of which required that the Company secure its commitments by providing letters of credit (see Notes 10, 11, 13, 14). The Company has entered into equity acquisition agreements in Russia which call for the Company 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). The Company has entered into a 15-year lease agreement for office space in Carpinteria, California. The Company has leased 50,000 square feet for approximately $74,000 per month with annual rent adjustments based on certain changes in the Consumer Price Index. The Company has entered into a sublease agreement for a portion of the office space which is not currently needed for operations. The Company has also entered into a sublease agreement for the office space that it previously occupied. Rents for the subleases approximate the Company's lease costs of these facilities. The Company's aggregate rental commitments for noncancellable agreements at December 31, 1998 are as follows (in thousands):
Minimum Lease Sublease Commitments Income ----------- ------ 1999 $ 1,737 $ (780) 2000 1,540 (761) 2001 1,437 (744) 2002 1,224 (744) 2003 1,224 (621) Thereafter 8,907 (338) ------- ------- $16,069 $(3,988) ======= =======
Rental expense was $2.1 million, $2.0 million and $2.2 million for the years ended December 31, 1998, 1997 and 1996, respectively. Sublease income was $0.3 million and $0.2 million for the years ended December 31, 1998 and 1996. The Company had no sublease income for the year ended December 31, 1997. NOTE 5 - TAXES ON INCOME The tax effects of significant items comprising the Company's net deferred income taxes as of December 31, 1998 and 1997 are as follows (in thousands):
1998 1997 ---- ---- Deferred tax assets: Operating loss carryforwards $ 33,446 $ 24,529 Difference in basis of property 6,757 - Other 10,250 338 Valuation allowance (47,375) (13,841) -------- --------- Total 3,078 11,026 -------- --------- Deferred tax liabilities: Difference in basis of property - (35,837) Other (102) - -------- --------- Net deferred tax asset (liability) $ 2,976 $ (24,811) ======== =========
S-14 51 51 The components of income before income taxes and minority interest are as follows (in thousands):
1998 1997 1996 ---- ---- ---- Income (loss) before income taxes United States $ (54,783) $ (5,989) $ 3,062 Foreign (175,912) 47,848 65,787 --------- -------- -------- Total $(230,695) $ 41,859 $ 68,849 ========= ======== ========
The provision for income taxes consisted of the following at December 31, (in thousands):
1998 1997 1996 ---- ---- ---- Current: United States $ 1,970 $ 4,617 $ 2,282 Foreign 1,597 4,728 1,547 --------- ------- ------- 3,567 9,345 3,829 --------- ------- ------- Deferred: United States 3,573 (3,573) - Foreign (31,360) 11,705 16,679 --------- ------- ------- (27,787) 8,132 16,679 --------- ------- ------- $ (24,220) $17,477 $20,508 ========= ======= =======
A comparison of the income tax expense at the federal statutory rate to the Company's provision for income taxes is as follows (in thousands):
1998 1997 1996 ---- ---- ---- Computed tax expense at the statutory rate $ (80,743) $14,651 $24,097 State income taxes, net of federal effect - 1,072 1,249 Rate differentials for foreign income 21,800 (314) (4,800) Change in valuation allowance and other 34,723 2,068 (38) --------- ------- ------- Income tax expense (benefit) $ (24,220) $17,477 $20,508 ========= ======= =======
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. At December 31, 1998 the Company had, for federal income tax purposes, operating loss carryforwards of approximately $90 million, expiring in the years 2003 through 2018. 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. The Company does 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 the Company's ongoing business. NOTE 6 - STOCK OPTIONS The Company adopted its 1988 Stock Option Plan in December 1988 authorizing options to acquire up to 418,824 shares of common stock. Under the plan, incentive stock options ("ISOs") were granted to a key employee and other non-qualified stock options ("NQSOs"), stock or bonus rights were granted to other key employees, directors, independent contractors and consultants at prices equal to or below market price, exercisable over various periods. The remaining options to purchase 80,000 shares of common stock for $4.89 per share were exercised during 1995. During 1989, the Company adopted its 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 to the plan. S-15 52 52 In September 1991, the Company 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, permits 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 officers and employees of the Company. 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 the 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 1991-1992 Stock Option 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, the Board of Directors of the Company terminated future grants under the 1991-1992 Stock Option Plan. The Directors' Stock Option Plan permits the granting of nonqualified stock options ("Director NQSOs") to purchase up to 400,000 shares of common stock to nonemployee directors of the Company. Upon election as a director and annually thereafter, each individual who serves as a nonemployee director automatically is 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 vest automatically on the date of the grant of the options, and at December 31, 1998, options to purchase 250,000 shares of common stock were both outstanding and exercisable. In June 1998, the shareholders of the Company approved the adoption of the 1998 Stock-Based Incentive Plan. The 1998 Stock-Based Incentive Plan authorizes up to 1,400,000 shares of the Company's common stock for grants of non-qualified and incentive stock options, stock appreciation rights, restricted stock awards and bonus stock awards to employees of the Company or its subsidiaries or associated companies. The exercise price of stock options granted under the plan must be no less than the fair market value of the Company's 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 the 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. A summary of the status of the Company's stock option plans as of December 31, 1998, 1997 and 1996 and changes during the years ending on those dates is presented below (shares in thousands):
1998 1997 1996 --------------------------- ---------------------------- --------------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE PRICE SHARES PRICE SHARES PRICE SHARES ----- ------ ----- ------ ----- ------ Outstanding at beginning of the $11.78 3,563 $10.78 3,037 $ 8.04 3,342 year: Options granted 8.62 513 14.32 889 19.33 658 Options exercised 7.77 (81) 6.61 (224) 6.69 (886) Options cancelled 13.88 (283) 14.41 (139) 12.14 (77) ----- ----- ----- Outstanding at end of the year 11.27 3,712 11.78 3,563 10.78 3,037 ===== ===== ===== Exercisable at end of the year 10.63 2,648 9.43 2,206 7.90 1,887 ===== ===== =====
Significant option groups outstanding at December 31, 1998 and related weighted average price and life information follow (shares in thousands):
NUMBER OUTSTANDING WEIGHTED-AVERAGE WEIGHTED- NUMBER WEIGHTED- RANGE OF AT REMAINING AVERAGE EXERCISABLE AT AVERAGE EXERCISE PRICES DECEMBER 31, 1998 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 1998 EXERCISE PRICE --------------- ----------------- ---------------- -------------- ----------------- -------------- $ 2.39 52 1.2 Years 2.39 52 2.39 4.89-7.00 789 3.8 Years 5.57 764 5.54 7.25-11.00 1,208 5.8 Years 8.83 828 8.86 11.50-16.50 1,107 7.9 Years 13.66 658 14.00 17.38-24.13 556 8.1 Years 20.75 346 20.96 ----- ----- 3,712 2,648 ===== =====
S-16 53 53 The weighted average fair value of the stock options granted from the 1998 Stock-Based Incentive Plan, 1991-1992 Stock Option Plan and the Directors' Stock Option Plan during 1998, 1997 and 1996 was $6.30, $9.83, $13.10 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:
1998 1997 1996 ---- ---- ---- Expected life 9.1 years 9.0 years 8.6 years Risk-free interest rate 5.5% 6.0% 6.2% Volatility 62% 54% 54% Dividend Yield 0% 0% 0%
The Company accounts for stock-based compensation in accordance with APB 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, the Company's pro forma net income and earnings per share for 1998, 1997 and 1996 would have been as follows (in thousands, except per share data):
1998 1997 1996 ---- ---- ---- Net Income (loss): Income (loss) before extraordinary charge $ (190,581) $13,343 $36,083 Extraordinary charge - - 10,075 ---------- ------- ------- Net income (loss) $ (190,581) $13,343 $26,008 ========== ======= ======= Net income (loss) per common share: Basic: Income (loss) before extraordinary charge $ (6.45) $ 0.46 $ 1.33 Extraordinary charge - - 0.37 ---------- ------- ------- Net income (loss) $ (6.45) $ 0.46 $ 0.96 ========== ======= ======= Diluted: Income (loss) before extraordinary charge $ (6.45) $ 0.44 $ 1.22 Extraordinary charge - - 0.34 ---------- ------- ------- Net income (loss) $ (6.45) $ 0.44 $ 0.88 ========== ======= =======
In connection with the acquisition of Benton Offshore China Company by the Company in December 1996, the Company 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 the Company's 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 the Company's common stock. All options were issued upon the acquisition of Benton Offshore China Company and vested upon issuance. At December 31, 1998, 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, 1998, a total of 208,500 options issued outside the plans were outstanding, 201,834 of which were vested. NOTE 7 - STOCK WARRANTS During the years ended December 31, 1996 and 1995, the Company issued a total of 587,783 and 125,000 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 July 1994, the Company 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 in senior unsecured notes, and in December 1994, 50,000 warrants were issued in connection with a revolving secured credit facility. In June 1995, 125,000 warrants were issued in connection with the issuance of $20 million in senior unsecured notes. S-17 54 54 In January 1996, 587,783 warrants were issued in connection with an exchange offer under which the Company acquired the outstanding limited partnership interests in three limited partnerships sponsored by the Company (see Note 2). During the years ended December 31, 1997 and 1996, 1,578 and 9,215, respectively, of the warrants were exercised. In November 1998, the Company extended by one year the expiration date of these warrants to January 18, 2000 and the Company recorded $135,000 of expense as a result of this warrant extension. The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at December 31, 1998 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 2000 11.00 588 577 ----- ----- 1,163 1,010 ===== =====
NOTE 8 - OPERATING SEGMENTS The Company regularly allocates resources to and assesses the performance of its operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Revenues from the Venezuela and Russia operating segments are derived primarily from the production and sale of oil. Revenues from USA and Other are 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, 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. The Company's investment in Severneftegaz has been included in the Russia operating segment.
USA AND INTER-SEGMENT 1998 (in thousands) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED - ------------------- --------- ------ ----- ------------ ------------ Revenue Oil and gas sales $ 82,215 $ 8,059 $ (3) - $ 90,271 Net gain on exchange rates 1,741 5,990 26 - 7,757 Investment earnings and other 806 205 14,014 (905) 14,120 Intersegment revenues - - 8,211 (8,211) - -------- -------- -------- ---------- --------- Total revenues 84,762 14,254 22,248 (9,116) 112,148 -------- -------- -------- ---------- --------- Expenses Lease operating costs and production taxes 39,069 5,626 (20) - 44,675 Depletion, depreciation and amortization 32,532 2,481 625 - 35,638 General and administrative 6,656 1,449 17,524 - 25,629 Interest 7,261 901 25,651 (905) 32,908 Intersegment expenses 8,211 - - (8,211) - -------- -------- -------- ---------- --------- Total expenses 93,729 10,457 43,780 (9,116) 138,850 -------- -------- -------- ---------- --------- Income (loss) before income taxes (8,967) 3,797 (21,532) - (26,702) Income taxes (29,955) 191 5,544 - (24,220) -------- -------- -------- ---------- --------- Operating segment income (loss) 20,988 3,606 (27,076) - (2,482) Write down and impairment of oil and gas properties (187,811) (10,100) (6,082) - (203,993) Minority interest 22,895 - - - 22,895 -------- -------- -------- ---------- --------- Net income (loss) $(143,928) $ (6,494) $(33,158) - $(183,580) ======== ======== ======== ========== ========= Capital expenditures $ 84,453 $ 18,009 $ 17,497 - $ 119,959 ======== ======== ======== ========== ========= Total assets $103,419 $ 66,189 $228,844 $ (59,831) $ 338,621 ======== ======== ======== ========== =========
S-18 55 55
USA AND INTER-SEGMENT 1997 (in thousands) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED - ------------------- --------- ------ ----- ------------ ------------ Revenues Oil and gas sales $ 154,119 $ 9,925 $ (87) - $ 163,957 Net gain on exchange rates 2,010 274 1 - 2,285 Investment earnings and other 1,666 182 11,864 (935) 12,777 Intersegment revenues - - 14,605 (14,605) - --------- -------- --------- --------- --------- Total revenues 157,795 10,381 26,383 (15,540) 179,019 --------- -------- --------- --------- --------- Expenses Lease operating costs and production taxes 34,516 7,349 22 - 41,887 Depletion, depreciation and amortization 44,107 3,079 406 - 47,592 General and administrative 8,708 1,786 12,942 - 23,436 Interest 7,412 166 17,602 (935) 24,245 Intersegment expenses 14,605 - - (14,605) - --------- -------- --------- --------- --------- Total expenses 109,348 12,380 30,972 (15,540) 137,160 --------- -------- --------- --------- --------- Income (loss) before income taxes 48,447 (1,999) (4,589) - 41,859 Income taxes 16,212 220 1,045 - 17,477 --------- -------- --------- --------- --------- Operating segment income (loss) 32,235 (2,219) (5,634) - 24,382 Minority interest (6,333) - - - (6,333) --------- -------- --------- --------- --------- Net income (loss) $ 25,902 $ (2,219) $ (5,634) - $ 18,049 ========= ======== ========= ========= ========= Capital expenditures $ 98,498 $ 3,582 $ 7,680 - $ 109,760 ========= ======== ========= ========= ========= Total assets $ 265,066 $ 43,611 $ 301,721 $ (26,121) $ 584,277 ========= ======== ========= ========= =========
USA AND INTER-SEGMENT 1996 (in thousands) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED - ------------------- --------- ------ ----- ------------ ------------ Revenues Oil and gas sales $136,840 $ 9,047 $ 1,816 - $ 147,703 Net gain on exchange rates 1,793 989 38 - 2,820 Investment earnings and other 829 87 6,676 (224) 7,368 Intersegment revenues - - 15,694 (15,694) - -------- ------- -------- ------- --------- Total segment revenues 139,462 10,123 24,224 (15,918) 157,891 Gain on sale of properties - - 7,175 - 7,175 -------- ------- -------- ------- --------- Total revenues 139,462 10,123 31,399 (15,918) 165,066 -------- ------- -------- ------- --------- Expenses Lease operating costs and production taxes 17,669 6,605 244 - 24,518 Depletion, depreciation and amortization 29,822 2,747 1,956 - 34,525 General and administrative 6,188 1,151 11,567 - 18,906 Interest 3,714 550 12,088 (224) 16,128 Intersegment expenses 15,694 - - (15,694) - -------- ------- -------- ------- --------- Total expenses 73,087 11,053 25,855 (15,918) 94,077 -------- ------- -------- ------- --------- Income (loss) before income taxes 66,375 (930) 5,544 - 70,989 Income taxes 17,966 259 2,283 - 20,508 -------- ------- -------- ------- --------- Operating segment income (loss) 48,409 (1,189) 3,261 - 50,481 Partnership exchange expenses - - (2,140) - (2,140) Minority interest (9,984) - - - (9,984) -------- ------- -------- ------- --------- Income (loss) before extraordinary charge $ 38,425 $(1,189) $ 1,121 - $ 38,357 ======== ======= ======== ======= ========= Capital expenditures $ 84,735 $ 6,047 $ 4,715 - $ 95,497 ======== ======= ======== ======= =========
S-19 56 56 NOTE 9 - RUSSIAN OPERATIONS In October 1997 and during 1998, GEOILBENT borrowed $10.2 million and $8.8 million, respectively, under parallel reserve-based loan agreements with the European Bank for Reconstruction and Development and International Moscow Bank. EBRD and IMB have agreed to lend up to a total of $65 million to GEOILBENT based on achieving certain reserve and production milestones. The proceeds from the loans will be used by GEOILBENT to develop the North Gubkinskoye Field in West Siberia, Russia (see Note 3). At December 31, 1998, the Company's share of borrowings under these agreements was $6.5 million. In March 1999, GEOILBENT borrowed an additional $8.3 million; the Company's share of this borrowing was $2.8 million. Additionally, a subsidiary of the Company recorded an account receivable for pipe it purchased for $5.0 million and sold to GEOILBENT at cost for use in the development of the field. The portion of the receivable not eliminated in consolidation is included in accounts receivable joint interest and other. During 1996 and 1997, the Company incurred $4.1 million in financing costs related to the establishment of the EBRD financing, which are recorded in other assets and are subject to amortization over the life of the facility. In 1998, under an agreement with EBRD, GEOILBENT'S board ratified an agreement to reimburse the Company for $2.6 million of such costs. However, due to GEOILBENT'S need for oil and gas investment and the declining prices for crude oil, the Company has agreed to defer payment of those reimbursements. Of the original $4.1 million, $1.5 million remains in other assets subject to amortization, and of the $2.6 million, the Company recorded the portion not eliminated in consolidation, $1.7 million, as a long-term receivable at December 31, 1998. For the period January 1 through June 30, 1996, the Company recorded an expense for a Russian oil export tariff of $0.8 million. GEOILBENT received a waiver from the export tariff for 1995. In July 1996, such oil export tariffs were terminated in conjunction with a loan agreement with the International Monetary Fund, but in 1999 new oil export tariffs were introduced. Excise, pipeline and other taxes (including a new oil export tariff introduced in 1999) continue to be levied on all oil producers and certain exporters. Although the Russian regulatory environment has become less volatile, the Company is unable to predict the impact of taxes, duties and other burdens for the future. In April 1998, the Company signed an agreement to earn a 40% equity interest in Severneftegaz. Severneftegaz 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 837,000 acres within and adjacent to the Urengoy field, Russia's largest producing natural gas field. Pursuant to a Cooperation Agreement between the Company and Severneftegaz, the Company will earn a 40% equity interest in exchange for providing the initial capital needed to achieve natural gas production. The Company's capital commitment will be in the form of providing or arranging a $100 million credit facility for the project, the terms of which have yet to be finalized, which is expected to be disbursed over the initial two-year development phase. The Company received fully voting shares representing a 40% ownership in Severneftegaz that contain restrictions on their sale and transfer. The Share Disposition Agreement provides for removal of the restrictions as disbursements are made under the credit facility. As of December 31, 1998, the Company had loaned $8.3 million to Severneftegaz pursuant to an interim credit facility, with interest at LIBOR plus 3%, and had earned the right to remove restrictions from shares representing an approximate 2% equity interest. Additionally, in December 1998 and January 1999, the Company purchased additional equity interests in Severneftegaz from another shareholder, bringing its total interest in unrestricted shares to approximately 9.5% at December 31, 1998 and 17.2% in January 1999. The Company owned a total of 47.5% of voting shares of Severneftegaz as of December 31, 1998 and a total of 55% of voting shares as of January 21, 1999. Due to the significant influence it exercises over the operating and financial policies of Severneftegaz, the Company has accounted for its interest in Severneftegaz using the equity method. The Company's share in the equity losses of Severneftegaz were not material for the year ended December 31, 1998. Certain provisions of Russian corporate law would effectively require minority shareholder consent in the making of new agreements between the Company and Severneftegaz, or to the changing of any terms in any existing agreements, including the conditions upon which the restrictions on the shares could be removed, between the two such as the Cooperation Agreement and the Share Disposition Agreement. NOTE 10 - VENEZUELA OPERATIONS On July 31, 1992, the Company and its partner, Venezolana de Inversiones y Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then one of three exploration and production affiliates of the national oil company, Petroleos de Venezuela, S.A. ("PDVSA") which have subsequently all been combined into PDVSA Petroleo y Gas, S.A. (all such parent, subsidiary and affiliated entities hereinafter referred to as "PDVSA"). The operating service agreement covers the Uracoa, Bombal and Tucupita fields that comprise the South Monagas Unit ("Unit"). Under the terms of the operating service agreement, Benton-Vinccler, C.A. ("Benton-Vinccler"), a corporation owned 80% by the Company and 20% by Vinccler, is a contractor for S-20 57 57 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. In January 1996, the Company and its bidding partners, Louisiana Land & Exploration, which has been subsequently acquired by Burlington Resources, Inc. ("Burlington"), and Norcen Energy Resources, LTD, which has been subsequently acquired by Union Pacific Resources Group Inc. ("UPR"), were awarded the right to explore and develop the Delta Centro Block in Venezuela. The contract requires a minimum exploration work program consisting of completing an 839 kilometer seismic survey and drilling three wells to depths of 12,000 to 18,000 feet within five years. PDVSA estimates that this minimum exploration work program will cost $60 million and requires that the Company and the other partners each post a performance surety bond or standby letter of credit for its pro rata share of the estimated work commitment expenditures. The Company has a 30% interest in the exploration venture, with Burlington and UPR each owning a 35% interest. Under the terms of the operating agreement, which establishes the management company of the project, Burlington will be the operator of the field and, therefore, the Company will not be 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% 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 the Company posted an $18 million standby letter of credit, collateralized in full by a time deposit of the Company, to secure its 30% share of the minimum exploration work program (see Note 4). As of December 31, 1998, the Company' share of expenditures to date was $8.2 million and the standby letter of credit had been reduced to $11.2 million. During the first quarter of 1999, drilling commenced on the Jarina-1 X, the first of the Block's exploration wells. NOTE 11 - CHINA OPERATIONS In December 1996, the Company 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 the Company's 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 a wholly owned subsidiary of the Company, continue as the operator and contractor of WAB-21. Benton Offshore China Company has submitted an exploration program and budget to CNOOC for 1998. However, due to certain territorial disputes over the sovereignty of the contract area, it is unclear when such program will commence. In October 1997, the Company signed a farmout agreement with Shell Exploration (China) Limited ("Shell") whereby the Company acquired a 50% participation interest in Shell's Liaohe area onshore exploration project in northeast China. Shell holds a petroleum contract with China National Petroleum Corporation ("CNPC") to explore and develop the deep rights in the Qingshui Block, a 563 square kilometer area (approximately 140,000 acres) in the delta of the Liaohe River. Shell will be the operator of the project. In July 1998, the Company paid to Shell 50% of Shell's prior investment in the Block, which was approximately $4 million ($2 million to the Company). The Company is required to pay 100% of the first $8 million of the costs for the phase one exploration period, after which any development costs will be shared equally. If a commercial well results from phase one and the Company elects to continue to phase two, then the Company will pay 100% of the first $8 million of the costs of the second phase of the exploration period, after which any development costs will be shared equally. If a commercial well does not result from phase one and the Company elects to continue to phase two, then the Company and Shell will share costs equally. The Company and Shell will share costs equally for the third exploration phase, if any. During the first quarter of 1999, drilling commenced on the Qing-22 Deep well as a part of the phase one exploration period activities. As of December 31, 1998, the Company had incurred $4.2 million related to the farmout agreement. NOTE 12 - SANTA BARBARA OPERATIONS In March 1997, the Company acquired a 40% participation interest in three California State offshore oil and gas leases from Molino Energy, which held 100% 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% participation interest in the leases, the Company became the operator of the project and paid 100% of the first $3.7 million and 53% of the remainder of the costs of S-21 58 58 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. The Company's share of the drilling and testing of the 2199 #7 well was $8.5 million. In November 1998, the Company entered into an agreement to acquire Molino Energy's interest in the leases in exchange for the release of its joint interest billing obligations of approximately $1.9 million. The agreement to acquire Molino Energy's interest will be finalized upon the completion of certain lot splits and the assignment of various permits and rights. NOTE 13 - JORDAN OPERATIONS In August 1997, the Company 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. The Sirhan Block consists of approximately 1.2 million acres (4,827 square kilometers) and is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the terms of the PSA, the Company is obligated to make certain capital and operating expenditures in up to three phases over eight years. The Company is obligated to spend $5.1 million in the first exploration phase, which is expected to last approximately two years. If the Company ultimately elects to continue through phases two and three, it would be obligated to spend an additional $18 million over the succeeding six years. During the first quarter of 1998, the Company reentered two wells and tested two different reservoirs. The WS-9 and WS-10 wells did not result in the production of commercial amounts of hydrocarbons. The Company will continue to reprocess and remap seismic data and conduct geological studies on the remaining prospectivity of the block. At December 31, 1998, the Company had incurred $3.7 million related to the PSA. NOTE 14 - SENEGAL OPERATIONS In December 1997, the Company signed a memorandum of understanding with Societe des Petroles du Senegal ("Petrosen"), the state oil company of the Republic of Senegal, to receive a minimum 45% working interest in and to operate the approximately one million acre onshore Thies Block in western Senegal. In addition, the Company obtained exclusive rights from Petrosen to evaluate and reprocess geophysical data for Senegal's shallow near-offshore acreage, an area encompassing approximately 7.5 million acres extending from the Mauritania border in the north to the Guinea-Bissau border in the south, and to choose certain blocks for further data acquisition and exploration drilling. The Company's working interest in any offshore discovery will be 85% with the remainder held by Petrosen. The Company's $5.4 million work commitment on the Thies Block, where Petrosen has recently drilled and completed the Gadiaga #2 discovery well, consists of hooking up the existing well, drilling two additional wells and constructing a 41-kilometer (approximately 25-mile) gas pipeline en route to Senegal's main electric generating facility near Dakar. At December 31, 1998, the Company had incurred $1.7 million related to both the onshore block and near-offshore acreage. NOTE 15 - RELATED PARTY TRANSACTIONS Prior to November 30, 1998 and during 1997 and 1996, the Company made unsecured loans documented by a promissory note bearing interest at 6% to Mr. A. E. Benton, its Chief Executive Officer. At December 31,1997 and September 30, 1998, the balances owed to the Company were $2.0 million and $4.4 million, respectively. In the fourth quarter of 1998, the Company loaned Mr. Benton an additional $1.1 million to enable him to reduce and eliminate his outstanding margin accounts with third parties that were secured by shares of the Company's stock. The Company 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 the Company by Mr. Benton, which is documented by a promissory note that bears interest at 6% and is payable on November 30, 1999, exceeded the value of the collateral, primarily due to the decline in the price of the Company's stock. As a result, the Company has recorded an allowance for doubtful accounts of $2.9 million. Measuring the amount of the allowance requires judgments and estimates, and the amount eventually realized may differ from the estimate. The portion of the note secured by the Company's stock and stock options has been presented on the balance sheet as a deduction from stockholders' equity. Also during 1998, 1997 and 1996, the Company made loans to Mr. M.B. Wray, its Vice Chairman, and Mr. J.M. Whipkey, its Chief Financial Officer, each loan bearing interest at 6% and collateralized by a security interest in personal real estate. At December 31, 1998, the balances owed to the Company by Mr. Wray and Mr. Whipkey were $0.6 million and $0.5 million, respectively and at December 31, 1997, the balances owed to the Company by Mr. Wray and Mr. Whipkey were $0.7 million and $0.5 million, respectively. In addition, other receivables from employees and directors of the Company amounted to $0.6 million and $0.3 million at December 31, 1998 and 1997, respectively. S-22 59 59 NOTE 16 - 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. SFAS 128 was adopted by the Company in December 1997 and earnings per share for all prior periods have been restated. The numerator (income) and denominator (shares) of the basic and diluted earnings per share computations for income before extraordinary charge were (in thousands, except per share amounts):
INCOME SHARES AMOUNT PER SHARE ------ ------ ---------------- 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 Loss available to common stockholders $(183,580) 29,554 $ (6.21) ========= ====== ======= FOR THE YEAR ENDED DECEMBER 31, 1997 - ------------------------------------ BASIC EPS Income available to common stockholders $ 18,049 29,119 $ 0.62 ========= ====== ======= Effect of Dilutive Securities: Stock options and warrants - 1,715 --------- ------ DILUTED EPS Income available to common stockholders and assumed conversions $ 18,049 30,834 $ 0.59 ========= ====== ======= FOR THE YEAR ENDED DECEMBER 31, 1996 - ------------------------------------ BASIC EPS Income available to common stockholders $ 38,357 27,088 $ 1.42 ========= ====== ======= Effect of Dilutive Securities: Convertible notes and debentures 33 223 Stock options and warrants - 2,502 --------- ------ DILUTED EPS Income available to common stockholders $ 38,390 29,813 $ 1.29 ========= ====== =======
For the years ended December 31, 1998, 1997 and 1996, 3,287,084, 581,324 and 135,579 options and warrants, respectively, were excluded from the earnings per share calculations because they were anti-dilutive. S-23 60 60 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, 1998 Revenues $ 33,258 $ 28,208 $ 23,879 $ 26,803 Expenses 55,293 89,423 31,817 166,310 -------- -------- -------- --------- Loss before income taxes and minority interest (22,035) (61,215) (7,938) (139,507) Income taxes (670) (7,294) 197 (16,453) -------- -------- -------- --------- Loss before minority interest (21,365) (53,921) (8,135) (123,054) Minority interest (379) (3,878) (296) (18,342) -------- -------- -------- --------- Net loss $(20,986) $(50,043) $ (7,839) $(104,712) ======== ======== ======== ========= Net loss per common share: Basic $ (0.71) $ (1.69) $ (0.27) $ (3.54) Diluted $ (0.71) $ (1.69) $ (0.27) $ (3.54)
QUARTER ENDED --------------------------------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- ------- ------------ ----------- (amounts in thousands, except per share data) YEAR ENDED DECEMBER 31, 1997 Revenues $46,299 $40,977 $45,188 $46,555 Expenses 28,966 30,418 36,603 41,173 ------- ------- ------- ------- Income before income taxes and minority interest 17,333 10,559 8,585 5,382 Income taxes 5,984 4,432 4,492 2,569 ------- ------- ------- ------- Income before minority interest 11,349 6,127 4,093 2,813 Minority interest 2,721 1,639 1,224 749 ------- ------- ------- ------- Net income $ 8,628 $ 4,488 $ 2,869 $ 2,064 ======= ======= ======= ======= Net income per common share: Basic $ 0.30 $ 0.15 $ 0.10 $ 0.07 Diluted $ 0.28 $ 0.15 $ 0.09 $ 0.07
SUPPLEMENTAL INFORMATION ON OIL AND 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 oil and gas exploration and production activities of the Company. 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 the Company's 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. S-24 61 61 TABLE I -TOTAL COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (IN THOUSANDS):
UNITED STATES AND VENEZUELA RUSSIA CHINA OTHER TOTAL --------- ------ ----- ----- ----- YEAR ENDED DECEMBER 31, 1998 Development costs $ 75,928 $ 13,276 $ - $ 2,105 $ 91,309 Exploration costs 4,230 3,550 4,024 7,853 19,657 -------- -------- --------- -------- -------- $ 80,158 $ 16,826 $ 4,024 $ 9,958 $110,966 ======== ======== ========= ======== ======== YEAR ENDED DECEMBER 31, 1997 Development costs $ 95,791 $ 2,652 $ - $ - $ 98,443 Exploration costs 3,919 33 1,088 5,718 10,758 -------- -------- --------- -------- -------- $ 99,710 $ 2,685 $ 1,088 $ 5,718 $109,201 ======== ======== ========= ======== ======== YEAR ENDED DECEMBER 31, 1996 Property acquisition costs $ - $ - $ 15,106 $ 1,139 $ 16,245 Development costs 82,197 6,047 - 1,498 89,742 Exploration costs 1,393 - 279 715 2,387 -------- -------- --------- -------- -------- $ 83,590 $ 6,047 $ 15,385 $ 3,352 $108,374 ======== ======== ========= ======== ========
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES (IN THOUSANDS):
UNITED STATES AND VENEZUELA RUSSIA CHINA OTHER TOTAL --------- ------ ----- ----- ----- DECEMBER 31, 1998 Proved property costs $ 371,369 $ 61,520 $ - $ 6,083 $438,972 Costs excluded from amortization 4,315 20,498 10,415 35,228 Oilfield inventories 7,214 2,080 - - 9,294 Less accumulated depletion and impairment (309,381) (20,857) - (6,083) (336,321) --------- --------- ------- --------- -------- $ 69,202 $ 47,058 $20,498 $ 10,415 $147,173 ========= ========= ======= ========= ======== DECEMBER 31, 1997 Proved property costs $ 283,469 $ 48,176 $ - $ - $331,645 Costs excluded from amortization 7,742 842 16,473 6,531 31,588 Oilfield inventories 3,627 896 - - 4,523 Less accumulated depletion (89,727) (8,276) - - (98,003) --------- --------- ------- --------- -------- $ 205,111 $ 41,638 $16,473 $ 6,531 $269,753 ========= ========= ======= ========= ======== DECEMBER 31, 1996 Proved property costs $ 182,566 $ 45,523 $ - $ - $228,089 Costs excluded from amortization 8,935 809 15,385 858 25,987 Oilfield inventories 5,545 - - - 5,545 Less accumulated depletion (46,143) (5,197) - - (51,340) --------- --------- ------- --------- -------- $ 150,903 $ 41,135 $15,385 $ 858 $208,281 ========= ========= ======= ========= ========
S-25 62 62 TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (IN THOUSANDS):
UNITED STATES AND VENEZUELA RUSSIA OTHER TOTAL --------- ------ ----- ----- YEAR ENDED DECEMBER 31, 1998 Oil and gas revenues $ 82,215 $ 8,059 $ (3) $ 90,271 Expenses: Lease operating costs and production taxes 39,069 5,626 (20) 44,675 Depletion 31,843 2,474 - 34,317 Write down and impairment of oil and gas properties 187,811 10,100 6,082 203,993 Income tax benefit (26,793) - - (26,793) ----------- --------- ------- ---------- Total expenses 231,930 18,200 6,062 256,192 ----------- --------- ------- ---------- Results of operations from oil and gas producing activities $ (149,715) $ (10,141) $(6,065) $ (165,921) =========== ========= ======= ========== YEAR ENDED DECEMBER 31, 1997 Oil and gas revenues $ 154,119 $ 9,925 $ (87) $ 163,957 Expenses: Lease operating costs and production taxes 34,516 7,349 22 41,887 Depletion 43,584 3,079 - 46,663 Income tax expense 25,656 - - 25,656 ----------- --------- ------- ---------- Total expenses 103,756 10,428 22 114,206 ----------- --------- ------- ---------- Results of operations from oil and gas producing activities $ 50,363 $ (503) $ (109) $ 49,751 =========== ========= ======= ========== YEAR ENDED DECEMBER 31, 1996 Oil and gas revenues $ 136,840 $ 9,047 $ 4,676 $ 150,563 Expenses: Lease operating costs and production taxes 17,669 6,605 244 24,518 Depletion 29,523 2,747 1,705 33,975 Income tax expense 24,429 - - 24,429 ----------- --------- ------- ---------- Total expenses 71,621 9,352 1,949 82,922 ----------- --------- ------- ---------- Results of operations from oil and gas producing activities $ 65,219 $ (305) $ 2,727 $ 67,641 =========== ========= ======= ==========
GEOILBENT (owned 34% by the Company) has been included in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, results of operations for oil and gas producing activities in Russia reflect the years ended September 30, 1998, 1997 and 1996. In May 1994, the Company entered into a commodity hedge agreement designed to reduce a portion of the Company's risk from oil price movements through December 31, 1996. Pursuant to the hedge agreement, the Company received $16.82 per Bbl and paid the average price per Bbl of West Texas Intermediate Light Sweet Crude Oil with regard to 1,500 Bbl of oil per day for 1996. During the year ended December 31, 1996 the Company incurred losses of $2.9 million under the hedge agreement which reduced oil and gas sales. The Company did not enter into any commodity hedging agreements during 1997 and 1998. S-26 63 63 TABLE IV - QUANTITIES OF OIL AND 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 the Company considers 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. Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and 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 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. 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. The Company's engineering estimates indicate that a significant quantity of natural gas reserves (net to the Company's interest) will be developed and produced in association with the development and production of the Company's proved oil reserves in Russia. The Company expects that, due to current market conditions, it will initially reinject or flare such associated natural gas production, and accordingly, no future net revenue has been assigned to these reserves. Under the joint venture agreement, such reserves are owned by the Company in the same proportion as all other hydrocarbons in the field, and subsequent changes in conditions could result in the assignment of value to these reserves. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. S-27 64 64 The evaluations of the oil and gas reserves as of December 31, 1998, 1997, 1996 and 1995 were audited by Huddleston & Co., Inc., independent petroleum engineers.
MINORITY INTEREST IN VENEZUELA RUSSIA TOTAL VENEZUELA NET TOTAL --------- ------ ----- --------- --------- PROVED RESERVES-CRUDE OIL, CONDENSATE, AND GAS LIQUIDS (MBBLS) YEAR ENDED DECEMBER 31, 1998 Proved reserves beginning of the year 94,671 26,113 120,784 (18,934) 101,850 Revisions of previous estimates 25,119 (2,283) 22,836 (5,024) 17,812 Extensions, discoveries and improved recovery 30,217 8,147 38,364 (6,043) 32,321 Production (12,172) (924) (13,096) 2,434 (10,662) ------- ------ ------- ------- ------- Proved reserves end of year 137,835 31,053 168,888 (27,567) 141,321 ======= ====== ======= ======= ======= YEAR ENDED DECEMBER 31, 1997 Proved reserves beginning of the year 86,076 23,544 109,620 (17,215) 92,405 Revisions of previous estimates 17,043 3,449 20,492 (3,409) 17,083 Extensions, discoveries and improved recovery 6,947 6,947 (1,389) 5,558 Production (15,395) (880) (16,275) 3,079 (13,196) ------- ------ ------- ------- ------- Proved reserves end of year 94,671 26,113 120,784 (18,934) 101,850 ======= ====== ======= ======= ======= YEAR ENDED DECEMBER 31, 1996 Proved reserves beginning of the year 73,593 22,618 96,211 (14,718) 81,493 Revisions of previous estimates (10,951) 712 (10,239) 2,190 (8,049) Extensions, discoveries and improved recovery 36,082 979 37,061 (7,216) 29,845 Production (12,648) (765) (13,413) 2,529 (10,884) ------- ------ ------- ------- ------- Proved reserves end of year 86,076 23,544 109,620 (17,215) 92,405 ======= ====== ======= ======= ======= PROVED DEVELOPED RESERVES AT: December 31, 1998 75,636 9,745 85,381 (15,127) 70,254 December 31, 1997 68,868 5,443 74,311 (13,774) 60,537 December 31, 1996 47,805 3,417 51,222 (9,561) 41,661 January 1, 1996 30,032 3,475 33,507 (6,006) 27,501
The Company began 1996 with 6 Mmcf of proved developed natural gas reserves in the United States. During 1996 the Company produced 1 Mmcf of the natural gas and sold the remaining 5 Mmcf of natural gas reserves in place. TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND 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 the Company cautions 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. 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 new tariffs were introduced in 1999. 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, the Company is unable to predict the impact of taxes, duties and other burdens for the future. S-28 65 65
MINORITY INTEREST IN VENEZUELA RUSSIA TOTAL VENEZUELA NET TOTAL --------- ------ ----- --------- --------- (amounts in thousands) DECEMBER 31, 1998 Future cash inflow $ 778,765 $ 183,524 $ 962,289 $(155,753) $ 806,536 Future production costs (527,856) (70,953) (598,809) 105,571 (493,238) Other related future costs (147,806) (25,048) (172,854) 29,561 (143,293) ---------- --------- ---------- --------- ---------- Future net revenue before income taxes 103,103 87,523 190,626 (20,621) 170,005 10% annual discount for estimated timing of cash flows (40,648) (37,977) (78,625) 8,130 (70,495) ---------- --------- ---------- --------- ---------- Discounted future net cash flows before income taxes 62,455 49,546 112,001 (12,491) 99,510 Future income taxes, discounted at 10% per annum - (6,298) (6,298) - (6,298) ---------- --------- ---------- --------- ---------- Standardized measure of discounted future net cash flows $ 62,455 $ 43,248 $ 105,703 $ (12,491) $ 93,212 ========== ========= ========== ========= ========== DECEMBER 31, 1997 Future cash inflow $ 923,421 $ 274,190 $1,197,611 $(184,684) $1,012,927 Future production costs (332,647) (74,326) (406,973) 66,529 (340,444) Other related future costs (70,415) (53,283) (123,698) 14,083 (109,615) ---------- --------- ---------- --------- ---------- Future net revenue before income taxes 520,359 146,581 666,940 (104,072) 562,868 10% annual discount for estimated timing of cash flows (156,321) (68,885) (225,206) 31,264 (193,942) ---------- --------- ---------- --------- ---------- Discounted future net cash flows before income taxes 364,038 77,696 441,734 (72,808) 368,926 Future income taxes, discounted at 10% per annum (72,567) (14,263) (86,830) 14,513 (72,317) ---------- --------- ---------- --------- ---------- Standardized measure of discounted future net cash flows $291,471 $ 63,433 $354,904 $ (58,295) $ 296,609 ========== ========= ========== ========= ========== DECEMBER 31, 1996 Future cash inflow $1,036,611 $ 291,951 $1,328,562 $(207,322) $1,121,240 Future production costs (347,498) (94,279) (441,777) 69,500 (372,277) Other related future costs (65,454) (45,723) (111,177) 13,091 (98,086) ---------- --------- ---------- --------- ---------- Future net revenue before income taxes 623,659 151,949 775,608 (124,731) 650,877 10% annual discount for estimated timing of cash flows (176,805) (61,244) (238,049) 35,361 (202,688) ---------- --------- ---------- --------- ---------- Discounted future net cash flows before income taxes 446,854 90,705 537,559 (89,370) 448,189 Future income taxes, discounted at 10% per annum (123,304) (17,282) (140,586) 24,661 (115,925) ---------- --------- ---------- --------- ---------- Standardized measure of discounted future net cash flows $323,550 $ 73,423 $396,973 $ (64,709) $ 332,264 ========== ========= ========== ========= ==========
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
YEARS ENDED DECEMBER 31, ------------------------ 1998 1997 1996 ---- ---- ---- (amounts in thousands) Balance, January 1 $ 354,904 $ 396,973 $ 261,995 Changes resulting from: Sales of oil and gas, net of related costs (46,755) (122,179) (121,954) Revisions to estimates of proved reserves Pricing (411,986) (102,357) 108,705 Quantities 11,627 82,211 (56,315) Sales of reserves in place - (18) Extensions, discoveries and improved recovery, net of future costs 46,748 25,725 183,968 Accretion of discount 44,174 53,756 37,230 Change in income taxes 80,532 53,756 (30,288) Development costs incurred 55,601 61,207 63,013 Changes in timing and other (29,142) (94,188) (49,363) --------- --------- --------- Balance, December 31 $ 105,703 $ 354,904 $ 396,973 ========= ========= =========
S-29 66 66 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, 1999. BENTON OIL AND GAS COMPANY (Registrant) Date: March 30, 1999 By: /s/A.E. Benton -------------------- --------------------------- A.E. Benton Chief Executive Officer and Principal 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, 1999, on behalf of the Registrant in the capacities indicated:
Signature Title - --------- ----- /s/A. E. Benton Chairman, Chief Executive Officer, - ------------------------------------- President and Director A. E. Benton (Principal Executive Officer) /s/James M. Whipkey Senior Vice President, Chief Financial - ------------------------------------- Officer and Treasurer James M. Whipkey (Principal Financial Officer) /s/Chris C. Hickok Vice President - Controller - ------------------------------------- Chris C. Hickok (Principal Accounting Officer) /s/Michael B. Wray Vice Chairman and Director - ------------------------------------- Michael B. Wray /s/Bruce M. McIntyre Director - ------------------------------------- Bruce M. McIntyre /s/Richard W. Fetzner Director - ------------------------------------- Richard W. Fetzner /s/Garrett A. Garrettson Director - ------------------------------------- Garrett A. Garrettson
67 67 EXHIBITS EX-21.1 2 EXHIBIT 21.1 1 68 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
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% by Benton Oil and Gas Company and GEOILBENT, Ltd. which is owned 34% by Benton Oil and Gas Company. EX-23.1 3 EXHIBIT 23.1 1 69 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 and 333-19679) and in the Prospectuses constituting part of the Registration Statements on Form S-3 (Nos. 33-70146, 33-79494, 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 25, 1999 appearing on page S-1 of this Form 10-K. PricewaterhouseCoopers LLP San Francisco, California March 30, 1999 EX-23.2 4 EXHIBIT 23.2 1 70 EXHIBIT 23.2 BENTON OIL AND GAS COMPANY INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-37124 and 333-19679 on Form S-8, 33-70146 on Form S-3, 333-00135 on Form S-3, 333-17231 on Form S-3, 33-79494 on Form S-3, 33-61299 on Form S-4, 33-42139 on Form S-4 and 333-06125 on Form S-4 of Benton Oil and Gas Company of our report dated March 24, 1998 appearing in this Annual Report on Form 10-K of Benton Oil and Gas Company for the year ended December 31, 1998. Deloitte & Touche LLP Los Angeles, California March 30, 1999 EX-23.3 5 EXHIBIT 23.3 1 71 EXHIBIT 23.3 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, 1998, 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 24, 1999 EX-27 6 EXHIBIT 27
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10K FOR THE PERIOD ENDED DECEMBER 31, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS YEAR DEC-31-1998 JAN-01-1998 DEC-31-1998 1 18,147 41,173 17,307 3,236 0 92,809 493,102 339,636 338,621 36,945 288,212 0 0 296 12,693 338,621 90,271 112,148 80,313 80,313 0 0 32,908 (230,695) (24,220) (183,580) 0 0 0 (183,580) (6.21) (6.21)
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