-----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, O5dS2CWS5JD3DKZUcvfxVsegAI2pgUwcc1gStJrcgaYUvvOGZLFj3E3rgLekwM+C 0yitecczNE/fMMDD41xJ9A== 0000950152-98-002841.txt : 19980401 0000950152-98-002841.hdr.sgml : 19980401 ACCESSION NUMBER: 0000950152-98-002841 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980331 SROS: NONE 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: 98581981 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 & 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) [X] of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1997 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) (I.R.S. Employer Identification Number) 1145 EUGENIA PLACE, 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 25, 1998, the aggregate market value of the shares of voting stock of Registrant held by non-affiliates was approximately $340,968,947 based on a closing sales price on NYSE of $11.8125. As of March 25, 1998, 29,521,396 shares of the Registrant's common stock were outstanding. DOCUMENT INCORPORATED BY REFERENCE Portions of the Registrant's Proxy Statement for the 1998 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 BENTON OIL AND GAS COMPANY FORM 10-K TABLE OF CONTENTS Page ---- Part I - ------ Item 1. Business.............................................................................3 Item 2. Properties..........................................................................20 Item 3. Legal Proceedings...................................................................20 Item 4. Submission of Matters to a Vote of Security Holders ................................21 Part II - ------- Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters........................................22 Item 6. Selected Consolidated Financial Data................................................23 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....................................25 Item 8. Financial Statements and Supplementary Data.........................................30 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ................................30 Part III - -------- Item 10. Directors and Executive Officers of the Registrant .................................31 Item 11. Executive Compensation..............................................................31 Item 12. Security Ownership of Certain Beneficial Owners and Management..................................................31 Item 13. Certain Relationships and Related Transactions .....................................31 Part IV - ------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................................................32 Financial Statements...............................................................................34 Signatures.........................................................................................59
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. 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, 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 and train 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 recently 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 also recently expanded into projects which involve exploration components, in Venezuela through its participation in the Delta Centro exploration block, in Santa Barbara County, California through the acquisition of a participation interest in three state offshore oil and gas leases, and in China through a farmout agreement with Shell Exploration (China) Limited ("Shell"). As of December 31, 1997, the Company had total assets of $584.3 million, total estimated proved reserves of 120.8 MBOE, and a standardized measure of discounted future net cash flow, before income taxes, for total proved reserves of $441.7 million. For the year ended December 31, 1997, the Company had total revenues of $179.0 million. The Company has been successful in increasing reserves, production, and revenues during the last four years. From year end 1993 through 1997, estimated proved reserves increased from 42,785 MBOE to 120,784 MBOE and net annual production increased from a total of 519 MBOE in 1993 to 16,275 MBOE in 1997. Earnings for the year ended December 31, 1997 were $18.0 million compared to earnings for the year ended December 31, 1996 of $28.3 million. The Company was incorporated in Delaware in September 1988. Its principal executive offices are located at 1145 Eugenia Place, 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 areas while 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. 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. 4 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. The Company has recently acquired rights to establish operations in the United States, China, Jordan and Senegal and is seeking similar opportunities to explore higher risk, higher potential prospects in other regions and areas. 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 by the Company in U.S. dollars while most operating costs are incurred in local currency. Pursuant to the operating 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. ("PDVSA") which have subsequently all been combined into PDVSA Petroleo y Gas, S.A. ("P&G"), the operating fees earned by the Company are paid directly to the Company'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) 1997 1996 1995 1997 1996 1995 -------- -------- -------- -------- -------- -------- RESERVE INFORMATION: Proved Reserves (MBOE) 94,671 86,076 73,593 26,113 23,544 22,618 Discounted Future Net Cash Flow Attributable to Proved Reserves, Before Income Taxes $364,038 $446,854 $286,916 $ 77,696 $ 90,705 $ 85,361 Standardized Measure of Future Net Cash Flows $291,471 $323,550 $206,545 $ 63,433 $ 73,423 $ 55,434 DRILLING AND PRODUCTION ACTIVITY: Gross Wells Drilled 27 33 19 7 5 25 Average Daily Production (BOE) 42,178 34,557 14,949 2,411 2,091 1,345
5
VENEZUELA (1) RUSSIA (2) -------------------------------- -------------------------------- (dollars in 000's) 1997 1996 1995 1997 1996 1995 -------- -------- -------- -------- -------- -------- FINANCIAL DATA: Oil and Gas Revenues $154,119 $136,840 $ 49,174 $ 9,925 $ 9,047 $ 6,016 Expenses: Lease Operating Costs and Production Taxes 34,516 17,669 6,483 7,349 6,605 2,764 Depletion 43,584 29,523 11,393 3,079 2,747 1,512 -------- -------- -------- -------- -------- -------- Total Expenses 78,100 47,192 17,876 10,428 9,352 4,276 -------- -------- -------- -------- -------- -------- Results of Operations from Oil and Gas Producing Activities $ 76,019 $ 89,648 $ 31,298 $ (503) $ (305) $ 1,740 ======== ======== ======== ======== ======== ======== (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 P&G 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 nine months ended September 30, 1995 and the twelve months ended September 30, 1996 and 1997, the end of the fiscal period for GEOILBENT. See Note 18 to the Company's Consolidated Financial Statements.
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 P&G 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 the Company 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 P&G 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, P&G maintains full ownership of equipment and capital infrastructure following its installation. Benton-Vinccler invoices P&G each quarter based on Bbls of oil accepted by P&G during the quarter, using quarterly adjusted contract service fees per Bbl, and receives its payments from P&G 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 $10.2 million in capital recovery fees. 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 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, 1997, proved reserves attributable to the Company's Venezuelan operations were 94,671 MBOE, which represented approximately 78% of the Company's proved reserves. Benton-Vinccler is currently developing the Oficina sands in the Uracoa Field, which contain 75% of the Unit's proved reserves and has begun the development of the Tucupita and Bombal fields which contain the remaining 25% 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. During March 1998 (through March 25), a total of approximately 84 wells were producing an average of approximately 39,400 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) -------- ---------- --------------------------- 1995: First Quarter 1 1 11,800 Second Quarter 1 2 11,300 Third Quarter 3 2 15,800 Fourth Quarter 1 8 20,800 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
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, 88 new wells have been drilled in the Uracoa Field using modern drilling and completion techniques that had not previously been utilized on the field, with 88 wells, or 100%, completed and placed on production, and eight injection wells have been drilled and two other wells converted to injectors. In December 1993, Benton-Vinccler commenced drilling 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 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 intends to continue this method of horizontal drilling in the development of the field with an estimated capital expenditure of $24.0 million in 1998. 7 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 2,500 Bbls of oil per day and 9,900 Bbls of water per day through December 1997. The Company's approach to the future development of the Tucupita Field is to process large volumes of fluid to access the remaining oil. Working under the assumption that this field was abandoned prematurely, the Company will use new technology, including large diameter wellbores and high volume pumps, to produce the reservoir at progressively higher water to oil ratios. Based on the performance of this pilot well, as well as the Company's analysis of high-quality 3-D seismic surveys, a significant redevelopment effort is now underway. A combination of horizontal, deviated and vertical wells will be drilled to exploit the remaining oil reserves. Beginning in early 1998, Benton-Vinccler will drill nine producing wells and two water injection wells, and will expand production facilities, at an estimated aggregate cost of $40.0 million. Currently, oil is being trucked from the Tucupita Field to the Uracoa processing facilities. Benton-Vinccler is analyzing 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 one well in the Bombal Field and reactivated another, resulting in current combined production of 800 Bbls of oil per day. Benton-Vinccler currently plans to further develop the Bombal Field beginning in late 1998 by drilling an additional evaluation well, at an anticipated cost of up to $2.6 million. CUSTOMERS AND MARKET INFORMATION Oil produced in Venezuela is delivered to P&G 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 P&G'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 P&G's storage facility. A continuous flow measuring unit is installed at Benton-Vinccler's facility, so that quantity is monitored constantly. P&G 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 P&G for that quarter's deliveries. P&G 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. 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 175 local employees. Benton-Vinccler also conducts ongoing community relations programs, providing medical care, training, equipment and supplies, and support for local schools, in both states in which the Unit falls. 8 DELTA CENTRO BLOCK, VENEZUELA GENERAL In January 1996, the Company and its bidding partners, Louisiana Land and Exploration ("LL&E"), which was recently acquired by Burlington Resources Inc., and Norcen Energy Company ("Norcen"), recently acquired by Union Pacific Resources Group Inc., 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 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 estimates that this minimum exploration work program will cost $60.0 million, and required that the Company, LL&E and Norcen 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 provided a standby letter of credit in the amount of $18.0 million. The Company has a 30% interest in the exploration venture, with LL&E and Norcen each owning a 35% interest. Under the terms of the operating agreement, which establishes the management company for the project, LL&E 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 in the eastern part of Venezuela. Although no significant exploratory activity has been conducted on the block, PdVSA has estimated that the area may contain recoverable 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 598 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 $8.0 million, of which $4.0 million had been spent through December 31, 1997. Following the initial interpretation of the seismic data, the venture intends to drill an initial exploration well during the fourth quarter of 1998, at a cost to the Company of approximately $4.3 million. COMMUNITY AND COUNTRY RELATIONS The Company conducts an ongoing community relations program in the area, providing medical care, equipment and supplies to the Waroa tribe which resides in this area. 9 NORTH GUBKINSKOYE, RUSSIA GENERAL In December 1991, the joint venture agreement forming GEOILBENT among the Company (34% interest) and two Russian partners, Purneftegasgeologia and Purneftegas (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, serves as Chairman of the Board of GEOILBENT. LOCATION AND GEOLOGY GEOILBENT develops, produces and markets crude oil from the North Gubkinskoye and the Prisklonovoye Fields 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 only 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 1998 (through March 25), approximately 43 wells were producing an average of approximately 8.3 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 ------------- --------------------- 1995: First Quarter 4 4,300 Second Quarter 1 5,600 Third Quarter 9 7,800 Fourth Quarter 11 7,900 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
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 including shaker screens, monitoring equipment and drilling and completion fluids, to drill and complete a well. To date, 14 previously drilled wells have been reactivated and 56 wells have been drilled in the field, with 46 wells, or 82%, completed and placed on production. Five drilling rigs are currently working on 10 pads in the field, and once all wells on the pad have been drilled, each such well will be tested for completion. 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"). GEOILBENT has a 1998 capital expenditure budget of approximately $65.0 million, of which $49.0 million would be used to drill approximately 60 wells in the North Gubkinskoye Field and $16.0 million for construction of production facilities. The initial tranche of $12.0 million has been advanced from the EBRD Credit Facility and additional borrowing will be based on achieving certain reserve and production milestones. Additional expenditures in excess of $12.0 million 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. 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 four full-time expatriates working with GEOILBENT and 230 local employees. The Company conducts an ongoing community relations program 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, the Company 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 approximate 3.5 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 the Company's 1998 capital investment in such projects could be about $10.0 million. WAB-21, SOUTH CHINA SEA GENERAL In December 1996, the Company acquired Crestone Energy Corporation ("Crestone"), a privately held company headquartered in Denver, Colorado. Crestone'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. 11 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 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. Geophysical data indicates the possibility of several geologic horizons with complete assemblages of source rocks, reservoir rocks and cap rocks. 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 Quing 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 contracted by the Company's predecessor 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. Thus far Vietnam has not responded favorably. Instead, Vietnam granted exploration and development rights to parts of the Contract Area to Conoco, a division of DuPont Corporation. Diplomatic efforts have been conducted to resolve the territorial dispute but have thus far been unsuccessful and any exploration activities will be subject to resolution of such dispute. The Company has recorded no reserves attributable to this petroleum contract. DRILLING AND DEVELOPMENT ACTIVITY The Company has submitted, and received approval of, an initial seismic program covering a portion of the Contract Area which anticipates capital expenditures by the Company of approximately $8.0 million during the first year of activity. However, until such time as the territorial dispute has been resolved, the Company does not anticipate making significant capital expenditures for exploration or development of the Contract Area. QINGSHUI BLOCK, CHINA GENERAL In October 1997, the Company signed a farmout agreement with Shell pursuant to which the Company will acquire 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 will be the operator of the project. 12 Pursuant to the petroleum contract, the first exploration period commenced November 1, 1996. In September 1997, Shell notified CNPC of its intention to continue with the first exploration phase. Pursuant to the terms of the contract, this nine month study phase required a work commitment to evaluate the deep potential of the block, with an expected minimum expenditure of $3.0 million dollars. 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 $8.0 million dollars. The second exploration phase must be completed within two years of commencement of that phase. Phase two requires Shell to drill and complete one Exploratory Well to 4,500 meters with a minimum expenditure of $8.0 million dollars. At the commencement of phase two, 10% of the phase one contract area must be relinquished. The third exploration phase must be completed within two years of commencement of such phase. Shell is required to drill and complete one additional exploratory well to 4,500 meters with a minimum expenditure of $8.0 million dollars. 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. Assuming that Shell and the Company have performed each of the three phases, the Company's maximum aggregate capital commitment will be $22.0 million. Following the 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 its 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. The Company is required to pay to Shell 50% of Shell's costs to date, estimated to be approximately $4.0 million, representing a cost to the Company of $2.0 million. In addition, the Company agrees to pay 100% of the first $8.0 million of the costs for the phase one exploration period, after which, costs will be shared equally. If the first phase of the exploration period results in a commercial discovery, the Company agrees to pay 100% of the first $8.0 million of the costs for the second phase of the exploration period, after which, costs will be shared equally. The Company and Shell will share costs equally for the third exploration phase. 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. The acreage is situated in a structurally complex half-graben basin, associated with a deep-seated wrench zone. The graben-fill consists of sediments containing oil prone source rocks, turbiditic to lacustrine deltaic reservoir sequences and lacustrine mudstone cap rocks. 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 Company expects to drill one exploration well in the block beginning in the fourth quarter of 1998 with an anticipated capital expenditure to the Company of approximately $10.0 million. 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. The project area covers the Molino, the Gaviota and the Caliente fields, located approximately 35 miles west of Santa Barbara, California. Molino Energy holds a 100% working interest in each of the leases. The Company serves as operator of the project. In consideration of the 40% participation interest, the Company will initially pay 100% of the costs of the first well to be drilled on the block, which began in March 1998. The Company's cost participation in the first well will be reduced to 53% when an amount equal to 70% of costs of $2.5 million incurred by Molino Energy prior to the agreement with the Company is paid from 47% of the Company's initial cost participation. The Company will then pay 40% of all subsequent costs. 13 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 Vaqueras 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. DRILLING AND DEVELOPMENT ACTIVITY In March 1998, the Company began drilling the first well in the project on Lease No. 2199 on the Gaviota structure from an onshore drillsite. The onshore drill site has immediate access to oil and gas pipelines. The well is planned to have a measured depth of 14,800 total feet, with a true vertical depth of 10,700 feet and a maximum horizontal displacement of about 6,800 feet. The well will target the Oligocene age Vacqueros and Eocene age Sacate/Matilija formations, which are known gas/condensate reservoirs in other nearby fields. The Company anticipates that the first well will cost approximately $4.0 million. 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; $8.0 million in the second exploration phase (3 years) for seismic acquisitions, geological studies, and expenses incurred in drilling Exploratory Wells; and $10.0 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. 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-10 well was tested in the Umm Sahm formation and did not result in the production of commercial amounts of hydrocarbons. The WS-9 well was tested in the Dubaydib formation and yielded good shows of gas with traces of light oil. The well was temporarily abandoned pending the evaluation of additional data. The remainder of 1998 will be devoted to reprocessing and remapping seismic data and conducting geological studies on the remaining prospectivity of the block. The Company anticipates cumulative capital expenditures of approximately $3 million through the end of 1998. 14 SENEGAL, AFRICA GENERAL In December 1997, the Company was awarded a 45% working interest in the approximately one million acre Thies block in the western portion of Senegal by the state company of 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 to 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 will have 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 Guinee-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 in Senegal. DRILLING AND DEVELOPMENT ACTIVITY The Company is reprocessing 1,565 kilometers of 2 dimensional 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 dimensional 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. EVALUATION OF ADDITIONAL OPPORTUNITIES The Company continues to evaluate and pursue additional domestic and international opportunities which fit within the Company's business strategy. The Company is currently evaluating certain exploration, development and/or acquisition opportunities, but it is not presently known whether, or on what terms, such evaluations will result in future agreements or acquisitions. RESERVES The following table sets forth information regarding estimates of proved reserves at December 31, 1997 prepared by the Company and audited by Huddleston & Co., Inc., independent petroleum engineers:
CRUDE OIL AND CONDENSATE (MBBL) -------------------------------- DEVELOPED UNDEVELOPED TOTAL -------- ------- ------- Venezuela(1) 68,868 25,803 94,671 Russia(2) 5,443 20,670 26,113 ------- ------- ------- Total 74,311 46,473 120,784 ======= ======= ======= (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 P&G, 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.
15 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 46% of the Company's total proved reserves were non-producing as of December 31, 1997. 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. 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 may and often do prove to be inaccurate. For the period ending December 31, 1997, the Company reported $441.7 million of discounted future net cash flows before income taxes from proved reserves based on the Commission's required calculations. PRODUCTION, PRICES AND LIFTING COST SUMMARY The following table sets forth by country net production, average sales prices and average lifting costs of the Company for the years ended December 31, 1997, 1996 and 1995:
YEARS ENDED DECEMBER -------------------------------------- 1997 1996 1995 ---------- ---------- --------- VENEZUELA Net Crude Oil Production (Bbl) 15,394,807 12,647,987 5,456,473 Average Crude Oil Sales Price ($ per Bbl) $10.01 $10.82 $9.01 Average Lifting Costs ($ per Bbl) 2.24 1.40 1.19 RUSSIA (1) Net Crude Oil Production (Bbl) 880,148 765,137 490,960 Average Crude Oil Sales Price ($ per Bbl) $11.28 $11.82 $12.25 Average Lifting Costs ($ per Bbl) 8.35 8.63 5.63 (1) The presentation for Russia includes information for the nine months ended September 30, 1995 and the twelve months ended September 30, 1996 and 1997, the end of the fiscal period for GEOILBENT. See Note 18 to the Company's Consolidated Financial Statements.
16 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. 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 P&G, Benton-Vinccler submits capital and operating budgets to P&G for approval. Capital expenditures to comply with Venezuelan environmental regulations relating to the reinjection of gas in the field and water disposal were $12.8 million in 1997 and are expected to be $8.0 million in 1998. Benton-Vinccler also submits requests for permits for drilling, seismic and operating activities to P&G, 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 SENIAT (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. DRILLING, ACQUISITION AND FINDING COSTS During the years ended December 31, 1997, 1996 and 1995, the Company spent approximately $109 million, $108 million and $74 million, respectively, for acquisitions of leases and producing properties, development and exploratory drilling, production facilities and additional development activities such as workovers and recompletions. 17 The Company has drilled or participated in the drilling of wells as follows:
YEARS ENDED DECEMBER 31, -------------------------------------------------------------------------- 1997 1996 1995 ---------------------- ---------------------- ---------------------- GROSS NET GROSS NET GROSS NET --------- --------- --------- --------- --------- --------- WELLS DRILLED: Exploratory: Crude oil - - - - 3 1.020 Natural gas - - 1 .375 3 .970 Dry holes - - - - 1 .375 Development:(1)(2) Crude oil 31 22.040 36 26.500 41 22.680 Natural Gas - - - - 1 .220 Dry Holes 1 .340 - - 1 .800 --------- --------- --------- --------- --------- --------- TOTAL 32 22.380 37 26.875 50 26.065 ========= ========= ========= ========= ========= ========= AVERAGE DEPTH OF WELLS (FEET) 6,659 8,008 7,847 PRODUCING WELLS (3): Crude Oil 124 78.960 113 74.300 77 44.701 Natural Gas - - - - 8 2.024 (1) In March 1995, the Company sold certain of its West Cote Blanche Bay Field interests in the field, a result of which was to substantially eliminate the Company's future participation in recompletion and redrilling activities, and in March 1996, the Company sold the remainder of its interests in the field. (2) In addition to the activities set forth in the table, the Company participated in the successful reactivation of one gross (.34 net) oil well in Russia during the year ended December 31, 1995. (3) 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 25, 1998, the Company was participating in the drilling of one well in Venezuela, five wells in Russia and one well in California. 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, 1997, the Company added, net of production and property sales, approximately 120.8 MBOE 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 2.30 per BOE. The Company's estimate of future development costs for its undeveloped proved reserves at December 31, 1997 was 1.96 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. 18 ACREAGE The following table summarizes the developed and undeveloped acreage owned, leased or under concession as of December 31, 1997.
DEVELOPED UNDEVELOPED ----------------- ------------------------ GROSS NET GROSS NET ------ ------ --------- --------- Venezuela 9,950 7,960 673,893 276,114 Russia 16,080 5,467 149,680 50,891 China - - 6,339,117 6,269,558 Jordan - - 1,192,752 1,192,752 Senegal 1,280 576 997,399 448,830 United States 5,002 1,700 18,100 10,696 ------ ------ --------- --------- Total 32,312 15,703 9,370,941 8,248,841 ====== ====== ========= =========
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, 1997, the Company had 71 employees augmented from time to time with independent consultants, as required. Benton-Vinccler had 175 employees, and GEOILBENT had 230 employees. TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE All Venezuelan reserves are attributable to an operating service agreement between Benton-Vinccler and P&G, 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, a unit of DuPont Corporation. 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. 19 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. "MBbl" means thousand barrels. "MMBbl" means million barrels. "BBbl" 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. 20 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 (including, in applicable instances, rights in one or more horizons which may be penetrated by existing wellbores, but which have not been tested) to which Proved Reserves have not been assigned by independent petroleum engineers. ITEM 2. PROPERTIES The principal executive offices of the Company are located in leased space in Carpinteria, California. The lease covering this facility expires in December 2004. The Company also has other offices located in leased space, none of which individually or in the aggregate are material. Additionally, the Company has entered into a 15 year lease agreement for office space currently under construction in Carpinteria, California. It is anticipated that the building will be ready for occupancy in late 1998. The Company will lease the entire building (50,000 square feet) for $72,500 per month, subject to adjustments for tenant improvements, with annual rent adjustments based on certain changes in the Consumer Price Index. The Company intends to sublet the portion of the new building which would not be immediately needed for operations and to sublet the space currently occupied in Carpinteria. 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 the 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 at the time of Tesla's acquisition, it was insolvent and that it paid a price in excess of the fair value of the property. The Company intends to vigorously contest the suit and in its management's opinion, while it is unlikely that the suit will result in a material adverse effect on the Company's financial statements, it is too early to assess the probability of such an outcome. 21 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, which is currently in the discovery stage. The Company will be forced to spend time and financial resources to defend or resolve these matters. In January 1996, the Company acquired all of the interests in three of the limited partnerships which are the subject of the arbitration, in exchange for shares of, and warrants to purchase shares of, the Company's common stock. In the arbitration proceeding, if any liability is found to exist, the arbitrator will 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 will consider such factors in his or her determination of damages if the allegations are found to be true and damages are awarded. In the normal course of the Company's business, there are various 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, 1997, no matter was submitted to a vote of security holders. 22 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, 1997, there were 29,522,110 shares of Common Stock outstanding held of record by approximately 1,102 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, 1996 to April 28, 1997 and on the NYSE thereafter.
YEAR QUARTER HIGH LOW --------------------------------------------------------------------------------- 1996 First quarter $ 16.63 $ 11.25 Second quarter 22.13 15.63 Third quarter 25.38 18.38 Fourth quarter 28.63 19.75 1997 24.75 14.63 First quarter 17.13 12.63 Second quarter 19.25 13.50 Third quarter 21.88 11.25 Fourth quarter 1998 First quarter (through March 25) 13.69 9.75
On March 25, 1998, the last sales price for the Common Stock as reported by NYSE was $11.81 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. 23 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, 1997, 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, ----------------------------------------------------------- 1997 1996 1995(2) 1994 1993 -------- -------- -------- -------- -------- (amounts in thousands, except per share data) STATEMENT OF OPERATIONS: Total revenues $179,019 $165,066 $ 65,068 $ 34,705 $ 7,503 Lease operating costs and production taxes 41,887 24,518 10,703 9,531 5,110 Depletion, depreciation and amortization 47,592 34,525 17,411 10,298 2,633 General and administrative expense 23,436 18,906 9,411 5,242 2,631 Interest expense 24,245 16,128 7,497 3,888 1,958 Partnership exchange expenses - 2,140 - - - Litigation settlement expenses - - 1,673 - - -------- -------- -------- -------- -------- Income (loss) before income taxes, minority interest and extraordinary charge 41,859 68,849 18,373 5,746 (4,829) Income taxes 17,477 20,508 2,478 698 - -------- -------- -------- -------- -------- Income (loss) before minority interest and extraordinary charge 24,382 48,341 15,895 5,048 (4,829) Minority interest 6,333 9,984 5,304 2,094 - -------- -------- -------- -------- -------- Income (loss) before extraordinary charge 18,049 38,357 10,591 2,954 (4,829) Extraordinary charge for early retirement of debt, net of tax benefit of $879 - 10,075 - - - -------- -------- -------- -------- -------- Net income (loss) $ 18,049 $ 28,282 $ 10,591 $ 2,954 $ (4,829) ======== ======== ======== ======== ======== Net income (loss) per common share: Basic: Income (loss) before extraordinary $ 0.62 $ 1.42 $ 0.42 $ 0.12 $ (0.26) charge Extraordinary charge - 0.38 - - - -------- -------- -------- -------- -------- Net income (loss) $ 0.62 $ 1.04 $ 0.42 $ 0.12 $ (0.26) ======== ======== ======== ======== ======== Diluted: Income (loss) before extraordinary $ 0.59 $ 1.29 $ 0.40 $ 0.12 $ (0.26) charge Extraordinary charge - 0.34 - - - -------- -------- -------- -------- -------- Net income (loss) $ 0.59 $ 0.95 $ 0.40 $ 0.12 $ (0.26) ======== ======== ======== ======== ======== Weighted average common shares outstanding: Basic 29,119 27,088 25,084 24,851 18,609 Diluted 30,834 29,813 26,673 25,325 18,609
24
AT DECEMBER 31, ----------------------------------------------------------------- 1997 1996 1995 (2) 1994 1993 --------- --------- --------- --------- --------- BALANCE SHEET DATA: (amounts in thousands) Working capital (deficit) $ 165,945 $ 98,417 $ (2,888) $ 21,785 $ 26,635 Total assets 584,277 435,745 214,750 162,561 108,635 Long-term obligations, net of current portion 280,016 175,028 49,486 31,911 11,788 Stockholders' equity (1) 197,732 174,899 103,681 88,259 84,021 (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. See Note 18 to the Consolidated Financial Statements.
25 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 in Russia reflect the nine months ended September 30, 1995 and the twelve months ended September 30, 1996 and 1997. 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 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), 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 Company's Consolidated Financial Statements). The following discussion of the results of operations and financial condition as of December 31, 1997 and 1996 and for each of the years in the three year period ended December 31, 1997, 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, 1997, primarily reflect the substantial growth of Benton-Vinccler in Venezuela. During 1997, Benton-Vinccler accounted for more than 90% of the Company's production, oil and gas sales and net income. Other major influences on the Company's results of operations during the year ended December 31, 1997 were the continuing maturation of the Uracoa oil field resulting in higher water handling, gas handling, workover, transportation and chemical costs and the issuance of $115.0 million of senior unsecured notes. The following table presents selected expense items as a percentage of oil and gas sales:
1997 1996 1995 ------ ------ ------ Lease Operating Costs and Production Taxes 25.5% 16.6% 17.2% Depletion, Depreciation and Amortization 29.0 23.4 28.0 General and Administrative 14.3 12.8 15.1 Interest 14.8 10.9 12.1
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). 26 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 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. YEARS ENDED DECEMBER 31, 1996 AND 1995 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 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). By comparison, the Company had revenues of $65.1 million for the year ended December 31, 1995. Expenses incurred during the period consisted of lease operating costs and production taxes of $10.7 million, depletion, depreciation and amortization expense of $17.4 million, general and administrative expense of $9.4 million, interest expense of $7.5 million, litigation settlement expenses of $1.7 million, income tax expense of $2.5 million and a minority interest of $5.3 million. Net income for the period was $10.6 million or $0.41 per share (diluted). Revenues increased $100.0 million, or 154%, during the year ended December 31, 1996 compared to the corresponding period of 1995 primarily due to increased oil sales in Venezuela. Sales quantities for the year ended December 31, 1996 from Venezuela and Russia were 12,647,987 Bbls and 765,137 Bbls, respectively, compared to 5,456,473 Bbls and 490,960 Bbls, respectively, for the year ended December 31, 1995. Prices for crude oil per Bbl averaged $10.82 (pursuant to terms of an operating service agreement) from Venezuela and $11.82 from Russia for the year ended December 31, 1996 compared to $9.01 and $12.25, respectively, for the year ended December 31, 1995. Domestic sales quantities for the year ended December 31, 1996 were 6,589 Bbls of crude oil and condensate and 1,523,106 Mcf of natural gas compared to 68,975 Bbls of crude oil and 3,784,830 Mcf of natural gas for the year ended December 31, 1995. Domestic prices per Bbl for crude oil and per Mcf for natural gas averaged $19.70 and $3.04 during the year ended December 31, 1996 compared to $15.79 and $1.77 during the year ended December 31, 1995. Revenues for the year ended December 31, 1996 were reduced by a loss of $2.9 million related to a commodity 27 hedge agreement compared to a loss of $0.7 million in 1995. Revenues for 1996 were increased by a foreign exchange gain of $2.8 million compared to a gain of $1.0 million in 1995. Expenses increased during 1996 as Benton-Vinccler's operations continued to grow significantly, but decreased as a percentage of oil and gas sales. Lease operating costs and production taxes increased $13.8 million, or 129%, during the year ended December 31, 1996 compared to 1995, partially offset by the sale of the Company's remaining interest in the West Cote Blanche Bay, Rabbit Island and Belle Isle Fields. Depletion, depreciation and amortization increased $17.1 million, or 98%, during the year ended December 31, 1996 compared to the corresponding period in 1995. Depletion expense per BOE produced from Venezuela, United States and Russia during the year ended December 31, 1996 was $2.33, $6.55 and $3.59, respectively, compared to $2.09, $5.98 and $3.08, respectively, during the previous year. The increase in general and administrative expenses of $9.5 million, or 101%, during the year ended December 31, 1996 compared to 1995 was primarily due to the implementation of certain consulting and related arrangements among Benton-Vinccler, the Company and Vinccler, Venezuelan municipal taxes (which are a function of growing oil revenues) and the Company's increased corporate activity associated with the growth of the Company's business. Interest expense increased $8.6 million, or 115%, in 1996 compared to 1995 primarily due to the issuance of $125 million in senior unsecured notes in May 1996. The Company incurred partnership exchange expense of $2.1 million during the year ended December 31, 1996 as a result of the completion of an exchange offer resulting in the liquidation of three limited partnerships (see Note 2 of Notes to the Consolidated Financial Statements). Income tax expense increased $18.0 million, or 720%, during the year ended December 31, 1996 compared to 1995 primarily due to increased taxable income in Venezuela. The net income attributable to the minority interest increased $4.7 million, or 89%, for 1996 compared to 1995 as a result of the increased profitability of Benton-Vinccler's operations in Venezuela. INTERNATIONAL OPERATIONS As a private contractor, Benton-Vinccler is subject to a statutory income tax rate of 34%. However, Benton-Vinccler reported a significantly lower effective tax rate for 1996 due to significant non-cash tax deductible expenses resulting from devaluations in Venezuela when Benton-Vinccler had net monetary liabilities in U.S. dollars. The Company cannot predict the timing or impact of future devaluations in Venezuela. A 3-D seismic survey is being conducted over the southwestern portion of the Delta Centro Block in Venezuela with an expected total cost to the Company during 1998 of approximately $4.0 million. Following the initial interpretation of the seismic data, an initial exploration well is expected to be drilled during the fourth quarter of 1998 at a cost to the Company of approximately $4.3 million. Subsequent seismic and drilling programs will be based on the results of the 1997-1998 activity. 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 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. In December 1996, the Company acquired Crestone, a privately held company headquartered in Denver, Colorado. Crestone'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, a unit of DuPont Corporation. 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. The Company, through Crestone, 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. The Company has recorded no 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 28 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 $18.0 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 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. The Company is required to pay to Shell 50% of Shell's costs to date, estimated to be approximately $4.0 million ($2 million to the Company) and to pay 100% of the costs for the phase one exploration period, with a maximum required expenditure of $8.0 million. If the first phase of the exploration period results in a commercial discovery and if the Company elects to continue to phase two, then the Company will pay 100% of the costs of the second phase of the exploration period, with a maximum required expenditure of $8.0 million. The Company and Shell will be responsible for the costs of the third exploration phase and the costs of development activities associated with any of the three phases in proportion to their interests. 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, 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. 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. 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, 1997, the Company realized net foreign exchange gains, primarily as a result of the decline in the value of the Venezuelan bolivar and the Russian rouble during periods when the Company's Venezuela-related subsidiaries and GEOILBENT had substantial net monetary liabilities denominated in bolivares and roubles. During the year ended December 31, 1997, the Company's net foreign exchange gains attributable to its 29 Venezuelan and Russian operations were $2.0 million and $0.3 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. 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) 1997 1996 1995 ---------- ---------- --------- Net cash provided by operating activities $ 93,948 $ 84,852 $ 32,349 Net cash used in investing activities (216,028) (164,772) (53,644) Net cash provided by financing activities 101,588 106,172 13,282 ---------- ---------- --------- Net increase (decrease) in cash $ (20,492) $ 26,252 $ (8,013) ========== ========== =========
At December 31, 1997, the Company had current assets of $224.3 million and current liabilities of $58.4 million resulting in working capital of $165.9 million and a current ratio of 3.84:1. This compares to the Company's working capital of $98.4 million and a current ratio of 2.89:1 at December 31, 1996. The increase of $67.5 million was due primarily to the issuance of $115 million of senior unsecured notes partially offset by expenditures related to the continuing development of the South Monagas Unit in Venezuela. CASH FLOW FROM OPERATING ACTIVITIES. During 1997, 1996 and 1995, net cash provided by operating activities was approximately $93.9 million, $84.9 million and $32.3 million, respectively. Cash flow from operating activities increased by $9.0 million and $52.6 million in 1997 and 1996, respectively, over the prior years due primarily to increased oil and gas production in Venezuela. CASH FLOW FROM INVESTING ACTIVITIES. During 1997, 1996 and 1995, the Company had drilling and production related capital expenditures of approximately $109.8 million, $95.5 million and $68.3 million, respectively. Of the 1997 expenditures, $96.7 million was attributable to the development of the South Monagas Unit in Venezuela, $2.7 million related to the development of the North Gubkinskoye Field in Russia, $3.1 million related to a 3-D seismic survey in the Delta Centro Block in Venezuela, $2.7 million related to the development of the Gaviota lease in Santa Barbara County, California, $1.3 million related to the development of the Sirhan Block in Jordan, and $3.3 million was attributable to other projects. The Company also sold certain oil and gas properties for net proceeds of approximately $34.6 million and $15.4 million in 1996 and 1995, respectively. The Company expects 1998 capital expenditures of approximately $125.0 million, including $22.0 million in expenditures for 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). Funding for the currently anticipated 1998 capital expenditures is expected to come from working capital, cash flow from operations or sales of property interests. The Company's indentures contain provisions which restrict the manner in which the Company can invest in certain of its current operations, including Geoilbent. Although the Company believes it has sufficient funding for its expected capital expenditures from working capital and cash flow from operations or sales of property interests, the Company may be restricted in the manner of funding certain of such capital expenditures due to such restrictions in the indentures. The Company continues to evaluate and pursue domestic and international opportunities which fit within the Company's business strategy. The Company is currently evaluating certain exploration, development and/or acquisition opportunities, but it is not presently known whether, or on what terms, such evaluations will result in future agreements or acquisitions. 30 CASH FLOW FROM FINANCING ACTIVITIES. In May 1996, the Company issued $125.0 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 agreement provides for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. At December 31, 1997, the Company was in compliance with all covenants of the indenture. In November 1997, the Company issued $115.0 million in 9.375% senior unsecured notes due November 1, 2007. The Company subsequently repurchased $10 million of the notes at their par value. The indenture agreement provides for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. At December 31, 1997, the Company was in compliance with all covenants of the indenture. The proceeds from the notes will be used for general corporate purposes, including the Company's ongoing exploration and development programs. The EBRD and IMB have agreed to lend a total of $65 million to GEOILBENT (owned 34% by the Company) under parallel reserve-based, non-recourse loan agreements. Initial funding of $10.2 million and $1.8 million occurred in October 1997 and January 1998. The proceeds from the loans will be used by GEOILBENT to develop the North Gubkinskoye and Prisklonovoye fields in West Siberia, Russia. Additional borrowings will be based on achieving certain reserve and production milestones. The Company's share of the borrowings are not included in the accompanying financial statements because they occurred subsequent to September 30, 1997, the end of the fiscal period for GEOILBENT (see Note 1 of Notes to the Consolidated Financial Statements). YEAR 2000 COMPLIANCE The Company does not expect the cost of converting its computer systems to year 2000 compliance will be material to its financial condition. The Company believes that it will be able to achieve year 2000 compliance by the end of 1999, and does not currently anticipate any disruption in its operations as a result of any failure by the Company to be in compliance. The Company does not currently have any information concerning the year 2000 compliance status of its suppliers and customers. STOCK REPURCHASE PROGRAM In June 1997, the Board of Directors instituted a treasury stock repurchase program under which the Company is authorized to purchase up to 1.5 million 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. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA The information required by this item is included herein on pages S-1 through S-25. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE No information is required to be reported under this item. 31 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT * ITEM 11. EXECUTIVE COMPENSATION * ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT * ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS * * Reference is made to information under the captions "Election of Directors", "Executive Officers", "Executive Compensation", "Security Ownership of Certain Beneficial Owners and Management", and "Certain Relationships and Related Transactions" in the Company's Proxy Statement for the 1998 Annual Meeting of Stockholders. 32
PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Index to Financial Statements: Page Independent Auditors' Report ...............................................................S-1 Consolidated Balance Sheets at December 31, 1997 and 1996 ..................................S-2 Consolidated Statements of Income for the Years Ended December 31, 1997, 1996 and 1995 ...........................................................S-3 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1997, 1996 and 1995 ...............................................S-4 Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995 ...........................................................S-5 Notes to Consolidated Financial Statements for the Years Ended December 31, 1997, 1996 and 1995 .....................................................S-7 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 (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)).
33 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 10.15) (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 Deloitte & Touche LLP. 23.2 Consent of Huddleston & Co., Inc. 27.1 Financial Data Schedule. - --------------------------- (b) Reports on Form 8-K No Form 8-K was filed during the last quarter of the registrant's fiscal year.
34 INDEPENDENT AUDITORS' REPORT - ---------------------------- Board of Directors and Stockholders Benton Oil and Gas Company Carpinteria, California We have audited the accompanying consolidated balance sheets of Benton Oil and Gas Company and subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three 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 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Los Angeles, California March 24, 1998 35 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS --------------------------- (in thousands)
DECEMBER ----------------------- 1997 1996 --------- --------- ASSETS CURRENT ASSETS: Cash and cash equivalents $ 11,940 $ 32,432 Restricted cash 48 4,500 Marketable securities 156,436 52,004 Accounts receivable: Accrued oil and gas revenue 45,379 50,137 Joint interest and other 8,029 9,860 Prepaid expenses and other 2,463 1,591 --------- --------- TOTAL CURRENT ASSETS 224,295 150,524 RESTRICTED CASH 74,288 68,000 OTHER ASSETS 12,497 6,186 PROPERTY AND EQUIPMENT: Oil and gas properties (full cost method - costs of $31,588 and $25,987 excluded from amortization in 1997 and 1996, respectively) 367,756 259,622 Furniture and fixtures 5,734 4,283 --------- --------- 373,490 263,905 Accumulated depletion and depreciation (100,293) (52,870) --------- --------- 273,197 211,035 --------- --------- $ 584,277 $ 435,745 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable, trade and other $ 43,490 $ 43,594 Accrued interest payable 5,533 3,776 Payroll and related taxes 1,799 1,862 Income taxes payable 4,535 889 Short term borrowings 1,530 853 Current portion of long term debt 1,463 1,133 --------- --------- TOTAL CURRENT LIABILITIES 58,350 52,107 DEFERRED INCOME TAXES 24,811 16,679 LONG TERM DEBT 280,016 175,028 MINORITY INTEREST 23,368 17,032 COMMITMENTS AND CONTINGENCIES 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 40,000 shares; issued 29,522 and 28,898 shares at December 31, 1997 and 1996, respectively 295 289 Additional paid-in capital 146,125 140,648 Retained earnings 52,011 33,962 Treasury stock, at cost, 50 shares in 1997 (699) - --------- --------- TOTAL STOCKHOLDERS' EQUITY 197,732 174,899 --------- --------- $ 584,277 $ 435,745 ========= =========
See notes to consolidated financial statements S-2 36 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME --------------------------------- (in thousands, except per share data)
YEARS ENDED DECEMBER 31, -------------------------------- 1997 1996 1995 -------- -------- -------- REVENUES Oil and gas sales $163,957 $147,703 $ 62,157 Gain on sale of properties 7,175 Net gain on exchange rates 2,285 2,820 998 Investment earnings and other 12,777 7,368 1,913 -------- -------- -------- 179,019 165,066 65,068 -------- -------- -------- EXPENSES Lease operating costs and production taxes 41,887 24,518 10,703 Depletion, depreciation and amortization 47,592 34,525 17,411 General and administrative 23,436 18,906 9,411 Interest 24,245 16,128 7,497 Partnership exchange expenses 2,140 Litigation settlement expenses 1,673 -------- -------- -------- 137,160 96,217 46,695 -------- -------- -------- INCOME BEFORE INCOME TAXES AND MINORITY INTEREST 41,859 68,849 18,373 INCOME TAXES 17,477 20,508 2,478 -------- -------- -------- INCOME BEFORE MINORITY INTEREST 24,382 48,341 15,895 MINORITY INTEREST 6,333 9,984 5,304 -------- -------- -------- INCOME BEFORE EXTRAORDINARY CHARGE 18,049 38,357 10,591 EXTRAORDINARY CHARGE FOR EARLY RETIREMENT OF DEBT, NET OF TAX BENEFIT OF $879 10,075 -------- -------- -------- NET INCOME $ 18,049 $ 28,282 $ 10,591 ======== ======== ======== NET INCOME PER COMMON SHARE: Basic: Income before extraordinary charge $ 0.62 $ 1.42 $ 0.42 Extraordinary charge - 0.38 - -------- -------- -------- Net Income $ 0.62 $ 1.04 $ 0.42 ======== ======== ======== Diluted: Income before extraordinary charge $ 0.59 $ 1.29 $ 0.40 Extraordinary charge - 0.34 - -------- -------- -------- Net Income $ 0.59 $ 0.95 $ 0.40 ======== ======== ========
See notes to consolidated financial statements. S-3 37 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY ----------------------------------------------- (in thousands)
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 COMMON ADDITIONAL RETAINED SHARES COMMON PAID-IN EARNINGS TREASURY TOTAL ISSUED STOCK CAPITAL (DEFICIT) STOCK --------------------------------------------------------------------------------------- BALANCE AT JANUARY 1, 1995 24,900 $ 249 $ 92,921 $ (4,911) $ 88,259 Issuance of common shares: Exercise of warrants 3 29 29 Exercise of stock options 273 3 1,335 1,338 Conversion of notes and debentures 333 3 3,507 3,510 Securities registration costs (46) (46) Net income 10,591 10,591 --------- --------- --------- --------- --------- BALANCE AT DECEMBER 31, 1995 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 ========= ========= ========= ========= ========= =========
See notes to consolidated financial statements. S-4 38 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS ------------------------------------- (in thousands)
YEARS ENDED DECEMBER 31, ----------------------------------------- 1997 1996 1995 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 18,049 $ 28,282 $ 10,591 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization 47,592 34,525 17,411 Net earnings from limited partnerships (58) Amortization of financing costs 1,390 670 185 (Gain) loss on disposition of assets 11 (6,950) 16 Partnership exchange expenses 2,140 Minority interest in undistributed earnings of subsidiary 6,336 9,984 5,304 Extraordinary charge for early retirement of debt 10,075 Deferred income taxes 8,132 16,679 Changes in operating assets and liabilities: Accounts receivable 6,589 (35,180) (12,882) Prepaid expenses and other (872) (1,377) 349 Accounts payable 1,381 21,328 9,905 Accrued interest payable 1,757 2,915 189 Payroll and related taxes (63) 1,036 300 Income taxes payable 3,646 725 1,039 --------- --------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES 93,948 84,852 32,349 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sale of property and equipment 34,638 15,408 Additions of property and equipment (109,760) (95,497) (68,288) Increase in restricted cash (13,436) (74,050) (1,864) Decrease in restricted cash 11,600 21,864 1,100 Purchases of marketable securities (291,943) (133,296) Maturities of marketable securities 187,511 81,292 Distributions from limited partnerships 277 --------- --------- --------- NET CASH USED IN INVESTING ACTIVITIES (216,028) (164,772) (53,644) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Net proceeds from exercise of stock options and warrants 5,483 17,818 1,320 Purchase of treasury stock (699) Proceeds from issuance of short term borrowings and notes payable 116,190 181,921 24,557 Payments on short term borrowings and notes payable (11,680) (76,469) (11,999) Prepayment premiums on debt retirement (10,632) Increase in other assets (7,706) (6,466) (596) --------- --------- --------- NET CASH PROVIDED BY FINANCING ACTIVITIES 101,588 106,172 13,282 --------- --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (20,492) 26,252 (8,013) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 32,432 6,180 14,193 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 11,940 $ 32,432 $ 6,180 ========= ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during the year for interest expense $ 20,860 $ 13,519 $ 7,012 ========= ========= ========= Cash paid during the year for income taxes $ 4,589 $ 3,287 $ 1,885 ========= ========= =========
See notes to consolidated financial statements. S-5 39 SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: 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 $1,485,000. During the year ended December 31, 1996, the Company acquired Crestone Energy Corporation ("Crestone"), 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 at $14.6 million. During the year ended December 31, 1996, $3,226,000 principal amount of the Company's 8% convertible notes and $4,310,000 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 $273,000. Also 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 $3,997,000. During the year ended December 31, 1995, $1,393,000 of the Company's 8% convertible notes and $2,118,000 of the Company's 8% convertible debentures were retired in exchange for 118,785 and 214,237 shares of the Company's common stock, respectively. During the year ended December 31, 1995, the Company financed the purchase of oil and gas equipment and services in the amount of $10,385,000 and leased office equipment in the amount of $54,000. Also during 1995, the Company acquired residential real estate for $1,725,000 in exchange for accounts and notes receivable from an officer of the Company totaling $1,181,000 resulting in an account payable of $544,000 (see Note 15). See notes to consolidated financial statements. S-6 40 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ------------------------------------------ YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 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 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 investments in limited partnerships and the Russia joint venture ("GEOILBENT") are proportionately consolidated based on the Company's ownership interest. GEOILBENT (owned 34% by the Company) has been included in the consolidated financial statements based on a fiscal period ending September 30. All material intercompany profits, transactions and balances have been eliminated. 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. 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, 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 and at December 31, 1996, consisted of $26.2 million in treasury securities and agreements to repurchase treasury securities, $19.8 million in commercial paper and $6.0 million in bankers' acceptances. ACCOUNTS RECEIVABLE The Company has recorded an allowance for doubtful accounts of $367,000 and $336,000 related to other accounts receivable at December 31, 1997 and 1996, respectively. 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. S-7 41 PROPERTY AND EQUIPMENT The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of oil and gas reserves are capitalized as incurred, including exploration overhead of $1,894,000, $1,441,000 and $2,282,000 for the years ended December 31, 1997, 1996 and 1995, respectively. Only overhead which 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 oil and gas properties are accumulated in cost centers on a country by country basis, subject to a cost center ceiling (as defined by the Securities and Exchange Commission). All capitalized costs of oil and gas properties (excluding unevaluated property acquisition and exploration costs) and the estimated future costs of developing proved reserves, are depleted over the estimated useful lives of the properties by application of the unit-of-production method using only proved oil and gas reserves. Depletion expense attributable to the Venezuelan cost center for the years ended December 31, 1997, 1996 and 1995 was $43,584,000, $29,523,000 and $11,393,000 ($2.83, $2.33 and $2.09 per equivalent barrel), respectively. Depletion expense attributable to the Russian cost center for the years ended December 31, 1997, 1996 and 1995 was $3,079,000, $2,747,000 and $1,512,000 ($3.50, $3.59 and $3.08 per equivalent barrel), respectively. Depletion expense attributable to the United States cost center for the years ended December 31, 1996 and 1995 was $1,705,000 and $4,187,000 ($6.55 and $5.98 per equivalent barrel), respectively. Depreciation of furniture and fixtures is computed using the straight-line method, with depreciation rates based upon the estimated useful life applied to the cost of each class of property. Depreciation expense was $879,000, $548,000 and $310,000 for the years ended December 31, 1997, 1996 and 1995, 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 is recorded, if necessary, to reduce net deferred income tax assets to the amount expected to be recoverable. 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 and, as a result, operations in those countries are remeasured in United States dollars and any 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. FAIR VALUE OF FINANCIAL INSTRUMENTS 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, 1997, was approximately $246.7 million (carrying value of $230.0 million). S-8 42 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. STOCK OPTIONS Statement of Financial Accounting Standards No. 123 ("SFAS 123") requires expanded disclosures of stock-based compensation arrangements and encourages (but does not require) compensation cost to be measured based on the fair value of the equity instrument awarded. The Company continues to apply APB Opinion No. 25 ("APB 25") to its stock based compensation awards to employees and discloses the required pro forma effect on net income and earnings per share (see Note 7). 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 1996 and 1995 have been reclassified to conform to the 1997 financial statement presentation. NOTE 2 - ACQUISITIONS AND SALES In March 1995, the Company sold its 32.5% working interest in certain depths (above approximately 10,575 feet) in the West Cote Blanche Bay Field for an adjusted sales price of approximately $14.9 million. 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. S-9 43 NOTE 3 - LONG TERM DEBT Long term debt consists of the following at December 31 (in thousands):
1997 1996 -------- -------- Senior unsecured notes with interest at 9.375% See description below $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 Other 1,479 1,161 -------- -------- 281,479 176,161 Less current portion 1,463 1,133 -------- -------- $280,016 $175,028 ======== ========
In November 1997, the Company issued $115 million in 9.375% senior unsecured notes due November 1, 2007.The Company subsequently repurchased $10 million of the notes at their par value. Interest on the notes is due May 1 and November 1 of each year, beginning May 1, 1998. The indenture agreement provides for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. At December 31, 1997, the Company was in compliance with all covenants of the indenture. The proceeds will be used for general corporate purposes, including the Company's ongoing exploration and development programs. 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 agreement provides for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. At December 31, 1997, the Company was in compliance with all covenants of the indenture. 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 and bears interest at LIBOR plus 6.125% (11.844% at December 31, 1997) and matures in August 1999. The Company will receive 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. The principal payment requirements for the long term debt outstanding at December 31, 1997 are as follows for the years ending December 31 (in thousands): 1998 $ 1,463 1999 50,013 2000 3 2001 - 2002 - Subsequent Years 230,000 -------- $281,479 ========
S-10 44 NOTE 4 - SHORT TERM BORROWINGS GEOILBENT has periodically received production payment advances against future oil shipments from export marketers. The advances are repaid through withholdings from oil sales on a monthly basis and bear interest at market rates. At December 31, 1997 and 1996, no amounts were outstanding under such production payment advances. GEOILBENT also entered into an agreement with Morgan Guaranty for a short term credit facility under which the Company provides cash collateral for the loans to GEOILBENT. At December 31, 1997 and 1996, the Company's proportionate share of the outstanding short term borrowings of GEOILBENT was $1.5 million and $0.9 million, respectively. NOTE 5 - 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 the 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 at the time of Tesla's acquisition, it was insolvent and that it paid a price in excess of the fair value of the property. The Company intends to vigorously contest the suit and in its management's opinion, while it is unlikely that the suit will result in a material adverse effect on the Company's financial statements, it is too early to assess the probability of such an 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. In April 1997, the plaintiffs commenced discovery. The Company intends to vigorously defend this action and does not believe the claims raised are meritorious. However, new developments could alter this conclusion at any time. The Company will be forced to expend time and financial resources to defend or resolve any such matters. The Company is also subject to ordinary litigation that is incidental to its business. None of the above matters 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 provides 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. Investors in partnerships which were sponsored by a third party have sued the Company on the theory that since it provided oil and gas drilling prospects to those partnerships and operated substantially all of their properties, it was responsible for alleged violations of securities laws in connection with the offer and sale of interests, contractual breach of fiduciary duty and fraud. The Company entered into a settlement agreement related to these claims, whereby the Company paid $990,000 to the plaintiffs in full settlement of these claims. Legal fees of $683,000 in addition to the settlement amount were included in litigation settlement expenses for the year ended December 31, 1995. The Company has entered into a 15 year lease agreement for office space currently under construction in Carpinteria, California. It is anticipated that the building will be ready for occupancy in late 1998. The Company will lease the entire building (50,000 square feet) for $72,500 per month, subject to adjustments for tenant improvements, with annual rent adjustments based on certain changes in the Consumer Price Index. The Company intends to sublet a portion of the building which would not be immediately needed for operations. S-11 45 The Company's aggregate rental commitments for noncancellable agreements at December 31, 1997, are as follows (in thousands):
Rental Commitments Sub-Lease ------------------ --------- 1998 $ 719 $ - 1999 1,277 337 2000 1,208 337 2001 1,190 337 2002 1,179 337 Thereafter 10,187 675 ------- ------- $15,760 $ 2,023 ======= =======
Rental expense was $2,037,000, $2,233,000 and $1,981,000 for the years ended December 31, 1997, 1996 and 1995, respectively. NOTE 6 - TAXES ON INCOME The tax effects of significant items comprising the Company's net deferred income taxes as of December 31, 1997 and 1996 are as follows (in thousands):
1997 1996 -------- -------- Deferred tax assets: Operating loss carryforwards $ 24,529 $ 20,970 Other 338 720 Valuation allowance (13,841) (14,498) -------- -------- Total 11,026 7,192 -------- -------- Deferred tax liabilities: Difference in basis of property (35,837) (23,871) -------- -------- Net deferred tax liability $(24,811) $(16,679) ======== ========
The components of income before income taxes and minority interest are as follows (in thousands):
1997 1996 1995 -------- -------- -------- Income (loss) before income taxes: United States $ (5,989) $ 3,063 $ (9,500) Foreign 47,848 65,787 27,873 -------- -------- -------- Total $ 41,859 $ 68,850 $ 18,373 ======== ======== ========
The provision for income taxes consisted of the following at December 31, (in thousands):
1997 1996 1995 -------- -------- -------- Current: United States $ 4,617 $ 2,282 $ 919 Foreign 4,728 1,547 1,559 -------- -------- -------- 9,345 3,829 2,478 -------- -------- -------- Deferred: United States (3,573) - - Foreign 11,705 16,679 - -------- -------- -------- 8,132 16,679 - -------- -------- -------- $ 17,477 $ 20,508 $ 2,478 ======== ======== ========
S-12 46 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):
1997 1996 1995 -------- -------- -------- Computed tax expense at the statutory rate $ 14,651 $ 24,097 $ 6,431 State income taxes, net of federal effect 1,072 1,249 919 Rate differential for foreign income (314) (4,800) (7,278) Change in valuation allowance and other 2,068 (38) 2,406 -------- -------- -------- Provision for income taxes $ 17,477 $ 20,508 $ 2,478 ======== ======== ========
At December 31, 1997, the Company had, for federal income tax purposes, operating loss carryforwards of approximately $63 million, expiring in the years 2003 through 2012. 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 has not provided for United States income taxes on $93 million of foreign subsidiaries' unremitted earnings at December 31, 1997 which are expected to be reinvested indefinitely. It is not practicable to determine the amount of income taxes that might be payable if such earnings are ultimately repatriated. NOTE 7 - 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. 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. 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, 1997, options to purchase 250,000 shares of common stock were both outstanding and exercisable. A summary of the status of the Company's stock option plans as of December 31, 1997, 1996 and 1995 and changes during the years ending on those dates is presented below (shares in thousands): S-13 47
1997 1996 1995 ------------------- ------------------- ------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE PRICE SHARES PRICE SHARES PRICE SHARES ------ ------ ------ ------ ------ ------ Outstanding at beginning of the year: $10.78 3,037 $ 8.04 3,342 $ 6.74 3,034 Options granted 14.32 889 19.33 658 13.86 558 Options exercised 6.61 (224) 6.69 (886) 4.92 (193) Options canceled 14.41 (139) 12.14 (77) 6.53 (57) ------ ------ ------ Outstanding at end of the year 11.78 3,563 10.78 3,037 8.04 3,342 ====== ====== ====== Exercisable at end of the year 9.43 2,206 7.90 1,887 6.76 2,209 ====== ====== ======
Significant option groups outstanding at December 31, 1997 and related weighted average price and life information follow (shares in thousands):
RANGE OF NUMBER OUTSTANDING WEIGHTED-AVERAGE WEIGHTED- NUMBER WEIGHTED- EXERCISE AT REMAINING AVERAGE EXERCISE EXERCISABLE AT AVERAGE PRICES DECEMBER 31, 1997 CONTRACTUAL LIFE PRICE DECEMBER 31, 1997 EXERCISE PRICE ------ ------------------- ------------------- ---------------- ----------------- -------------- $ 2.39 52 2.2 Years $ 2.39 52 $ 2.39 4.89 - 7.00 765 4.4 Years 5.52 765 5.52 7.50 - 10.88 880 5.2 Years 8.86 869 8.85 11.50 - 16.50 1,269 9.0 Years 13.74 328 14.35 17.38 - 24.13 597 9.1 Years 20.76 192 21.10 ------ ----- 3,563 2,206 ====== =====
The weighted average fair value of the stock options granted from the 1991-1992 Stock Option Plan and the Directors' Stock Option Plan during 1997, 1996 and 1995 was $9.83, $13.10, $8.92 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:
1997 1996 1995 ---------- --------- ------- Expected life 9.0 years 8.6 years 7.5 years Risk-free interest rate 6.0% 6.2% 6.0% Volatility 54% 54% 54% Dividend yield 0% 0% 0%
The Company accounts for stock-based compensation in accordance with APB 25, 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 1997, 1996 and 1995 would have been as follows (in thousands, except per share data):
1997 1996 1995 ------- ------- ------- Net income: Income before extraordinary charge $13,343 $36,083 $10,369 Extraordinary charge - 10,075 - ------- ------- ------- Net income $13,343 $26,008 $10,369 ======= ======= ======= Net income per common share: Basic: Income before extraordinary charge $ 0.46 $ 1.33 $ 0.41 Extraordinary charge - 0.37 - ------- ------- ------- Net income $ 0.46 $ 0.96 $ 0.41 ======== ========= ========= Diluted: Income before extraordinary charge $ 0.44 $ 1.22 $ 0.39 Extraordinary charge - 0.34 - ------- ------- ------- Net income $ 0.44 $ 0.88 $ 0.39 ======== ========= =========
S-14 48 In connection with the acquisition of Crestone by the Company in December 1996, the Company adopted the Crestone Energy Corporation 1996 Stock Option Plan. Under the plan, Crestone 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 Crestone's stock option plan and all options to purchase shares of Crestone 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 Crestone and vested upon issuance. At December 31, 1997, options to purchase 98,713 shares of common stock were both outstanding and exercisable. In addition to options issued pursuant to the plans, options for 10,000 and 15,000 shares of common stock were issued in 1997 and 1995, respectively, 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, 1997, a total of 208,500 options issued outside the plans were outstanding, 183,500 of which were vested. NOTE 8 - 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. 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. The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at December 31, 1997 were (shares in thousands):
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING - ------------------------------------------------------------------------------------------------- July 1994 July 2004 $ 7.50 150 8 250 September 1994 September 2002 9.00 250 50 December 1994 December 2004 12.00 50 125 June 1995 June 2007 17.09 125 January 1996 January 1999 11.00 588 577 ----- ----- 1,163 1,010 ===== =====
NOTE 9 - RUSSIAN OPERATIONS The European Bank for Reconstruction and Development ("EBRD") and International Moscow Bank ("IMB") have agreed to lend a total of $65 million to GEOILBENT (owned 34% by the Company) under parallel reserve-based, non-recourse loan agreements ("GEOILBENT Credit Facility"). Initial funding of $10.2 million and $1.8 million occurred in October 1997 and January 1998. The proceeds from the loans will be used by GEOILBENT to develop the North Gubkinskoye and Prisklonovoye fields in West Siberia, Russia. Additional borrowings will be based on achieving certain reserve and production milestones. The Company's share of the borrowings are not included in the accompanying financial statements because they occurred subsequent to September 30, 1997, the end of the fiscal period for GEOILBENT. S-15 49 For the period January 1 through June 30, 1996, the Company recorded an expense for the Russian export tariff of $845,000. GEOILBENT received a waiver from the export tariff for 1995 and in July 1996, such oil export tariffs were terminated in conjunction with a loan agreement with the International Monetary Fund. 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. 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. ("P&G"). 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 P&G 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 ("LL&E"), which was recently acquired by Burlington Resources, Inc., and Norcen Energy Resources, LTD ("Norcen"), recently acquired by Union Pacific Resources Group Inc., 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 a 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, LL&E and Norcen 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 LL&E and Norcen each owning a 35% interest. Under the terms of the operating agreement, which establishes the management company of the project, LL&E 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, which is collateralized in full by a time deposit of the Company, to secure its 30% share of the minimum exploration work program (see Note 5). As of December 31, 1997, the Company' share of expenditures to date was $4.0 million. NOTE 11 - CHINA OPERATIONS In December 1996, the Company acquired Crestone, 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 at $14.6 million. Crestone'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. Crestone will, as a wholly owned subsidiary of the Company, continue as the operator and contractor of WAB-21. Crestone has submitted an exploration program and budget to CNOOC for 1997. 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 will acquire a 50% participation interest in Shell's Liaohe area onshore exploration projection in northeast China. Shell holds a petroleum contract with China National Petroleum Corporation ("CNPC") to explore and develop S-16 50 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. The Company is required to pay to Shell 50% of Shell's costs to date, estimated to be approximately $4.0 million ($2 million to the Company) and to pay 100% of the first $8.0 million of the costs for the phase one exploration period, after which, costs will be shared equally. If the first phase of the exploration period results in a commercial discovery and if the Company elects to continue to phase two, then the Company will pay 100% of the first $8.0 million of the costs of the second phase of the exploration period, after which, costs will be shared equally. The Company and Shell will share costs equally for the third exploration phase. As of December 31, 1997, the Company had incurred $0.2 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. The project area covers the Molino, the Gaviota and the Caliente fields, located approximately 35 miles west of Santa Barbara, California. Molino Energy holds a 100% working interest in each of the leases. The Company serves as operator of the project. In consideration of the 40% participation interest, the Company will initially pay 100% of the costs of the first well to be drilled on the block, which began in March 1998. The Company's cost participation in the first well will be reduced to 53% when an amount equal to 70% of costs of $2.5 million incurred by Molino Energy prior to the agreement with the Company is paid from 47% of the Company's initial cost participation. The Company will then pay 40% of all subsequent costs. As of December 31, 1997, the Company had incurred $2.7 million related to the project. 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 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. At December 31, 1997, the Company had incurred $1.3 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. NOTE 15 - RELATED PARTY TRANSACTIONS In December 1995, the Company purchased a home from Mr. A. E. Benton, its Chief Executive Officer, for $1.7 million, based on independent appraisals, and from the proceeds Mr. Benton repaid the balance owed to the Company of $593,000 plus accrued interest and a $300,000 loan guaranteed by the Company. During 1996 and 1997, the Company made loans to Mr. Benton, Mr. M.B. Wray, its Vice Chairman, and Mr. J.M. Whipkey, its Chief Financial Officer, each loan bearing interest at 6%. At December 31, 1996, the balances owed to the Company by Mr. Benton and Mr. Wray were $0.3 million and $0.6 million, respectively. At December 31, 1997, the balances owed to the Company by Mr. Benton, Mr. Wray and Mr. Whipkey were $2.0 million, $0.7 million and $0.5 million, respectively. S-17 51 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, 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 $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 and assumed conversions $38,390 29,813 $1.29 ======= ====== ===== FOR THE YEAR ENDED DECEMBER 31, 1995 BASIC EPS Income available to common stockholders $10,591 25,084 $0.42 ======= ====== ===== Effect of Dilutive Securities: Stock options and warrants -- 1,589 ------- ------ DILUTED EPS Income available to common stockholders $10,591 26,673 $0.40 ======= ====== =====
For the years ended December 31, 1997, 1996 and 1995, 581,324, 135,579, and 117,562 options, respectively, were excluded from the earnings per share calculations because they were anti-dilutive. NOTE 17 - MAJOR CUSTOMERS The Company is principally involved in the business of oil and gas exploration and production. P&G was the only oil and gas purchaser which represented more than 10% of the Company's oil and gas revenues during the years ended December 31, 1997, 1996 and 1995, representing 94%, 93% and 79%, respectively. S-18 52 NOTE 18 - OIL AND GAS ACTIVITIES Total costs incurred in oil and gas acquisition, exploration and development activities were (in thousands):
UNITED STATES AND VENEZUELA RUSSIA CHINA OTHER TOTAL --------- ------ ----- ----- ----- 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 ======= ======= ======= ======== ======== YEAR ENDED DECEMBER 31, 1995 Property acquisition costs $ 436 $ 436 ------- ------- -------- -------- Development costs $ 54,533 $ 12,374 5,463 72,370 Exploration costs 112 593 705 ------- ------- -------- -------- $ 54,645 $ 12,374 $6,492 $73,511 ======== ======== ======== ========
The Company's aggregate amount of capitalized costs related to oil and gas producing activities consists of the following at December 31 (in thousands):
UNITED STATES AND VENEZUELA RUSSIA CHINA OTHER TOTAL --------- ------ ----- ------------ ----- 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 ========= ======== ======= ======== ========= DECEMBER 31, 1995 Proved property costs $ 93,911 $ 37,070 $ 130,981 Costs excluded from amortization 14,001 3,215 $ 709 17,925 Properties held for sale (net of accumulated depletion of $8,344,830) 22,885 22,885 Oilfield inventories 5,307 13 5,320 Less accumulated depletion (16,620) (2,450) (19,070) --------- -------- -------- --------- $ 96,599 $ 37,835 $ 23,607 $ 158,041 ========= ======== ======== =========
S-19 53 The Company regularly evaluates its unproved properties to determine whether impairment has occurred. The Company has excluded from amortization its interest in unproved properties, the cost of uncompleted exploratory activities, and portions of major development costs. The principal portion of such costs, excluding those related to the acquisition of Crestone, 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 Crestone will be included in amortizable costs is uncertain. Excluded costs at December 31, 1997 consisted of the following by year incurred (in thousands):
TOTAL 1997 1996 1995 PRIOR TO 1995 ----- ---- ---- ---- ------------- Property acquisition costs $15,106 $15,106 Exploration costs 16,482 13,195 2,042 $351 $894 ------- ------- ------- ---- ---- $31,588 $13,195 $17,148 $351 $894 ======= ======= ======= ==== ====
Results of operations for oil and gas producing activities were (in thousands):
VENEZUELA RUSSIA UNITED STATES TOTAL --------- ------ ------------- ----- 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 -------- -------- -------- -------- Total expenses 78,100 10,428 22 88,550 -------- -------- -------- -------- Results of operations from oil and gas producing activities $ 76,019 $ (503) $ (109) $ 75,407 ======== ======== ======== ======== 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 6,605 243 24,517 Depletion 29,523 2,747 1,705 33,975 -------- -------- -------- -------- Total expenses 47,192 9,352 1,948 58,492 -------- -------- -------- -------- Results of operations from oil and gas Producing activities $ 89,648 $ (305) $ 2,728 $ 92,071 ======== ======== ======== ======== YEAR ENDED DECEMBER 31, 1995 Oil and gas revenues $ 49,174 $ 6,016 $ 7,683 $ 62,873 Expenses: Lease operating costs and production taxes 6,483 2,764 1,456 10,703 Depletion 11,393 1,512 4,188 17,093 -------- -------- -------- -------- Total expenses 17,876 4,276 5,644 27,796 -------- -------- -------- -------- Results of operations from oil and gas producing activities $ 31,298 $ 1,740 $ 2,039 $ 35,077 ======== ======== ======== ========
Beginning in 1995, 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 for 1995 reflect the nine months ended September 30, 1995. Oil and gas revenues and expenses in Russia for the quarter ended December 31, 1995 of $2.4 million and $2.0 million, respectively, have been included in the Company's consolidated results of operations for 1996. S-20 54 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. Such terms applied to production of 1,000 Bbl of oil per day for 1994, 1,250 Bbl of oil per day in 1995 and 1,500 Bbl of oil per day for 1996. During the years ended December 31, 1996 and 1995, respectively, the Company incurred losses of $2,860,000 and $716,000, respectively, under the hedge agreement which reduced oil and gas sales. QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED) 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 P&G, under which all mineral rights are owned by the government of Venezuela. Sales of reserves in place in 1995 include reserves related to the United States properties sold in April 1996 (see Note 2), respectively. The evaluations of the oil and gas reserves as of December 31, 1997, 1996, 1995 and 1994 were audited by Huddleston & Co., Inc., independent petroleum engineers.
UNITED MINORITY INTEREST VENEZUELA RUSSIA STATES TOTAL IN VENEZUELA NET TOTAL ----------------------------------------------------------------------------- PROVED RESERVES - CRUDE OIL, CONDENSATE, AND GAS LIQUIDS (MBBLS) 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 6,947 6,947 (1,389) 5,558 recovery 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 36,082 979 37,061 (7,216) 29,845 recovery 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 ======= ====== ======= ======= ======= YEAR ENDED DECEMBER 31, 1995 Proved reserves beginning of the year 60,707 17,540 233 78,480 (12,141) 66,339 Revisions of previous estimates (12,877) (107) (12,984) 2,575 (10,409) Extensions, discoveries and improved 31,219 5,569 91 36,879 (6,243) 30,636 recovery Production (5,456) (491) (69) (6,016) 1,091 (4,925) Sales of reserves in place (148) (148) (148) --------- ---------- ------ --------- ----------- -------- Proved reserves end of year 73,593 22,618 0 96,211 (14,718) 81,493 ====== ====== ======= ======== ======== ======== PROVED DEVELOPED RESERVES AT: December 31, 1997 68,868 5,443 74,311 (13,774) 60,537 December 31, 1996 47,805 3,417 0 51,222 (9,561) 41,661 December 31, 1995 30,032 3,475 0 33,507 (6,006) 27,501 January 1, 1995 12,580 2,772 155 15,507 (2,516) 12,991 PROVED RESERVES - NATURAL GAS (MMCF) YEAR ENDED DECEMBER 31, 1996 Proved reserves beginning of the year 6 6 6 Production (1) (1) (1) Sales of reserves in place (5) (5) (5) --------- -------- --------- Proved reserves end of year 0 0 0 ========= ========= ========= YEAR ENDED DECEMBER 31, 1995 Proved reserves beginning of the year 16,077 16,077 16,077 Revisions of previous estimates (5,395) (5,395) (5,395) Extensions, discoveries and improved 12,927 12,927 12,927 recovery Production (3,785) (3,785) (3,785) Sales of reserves in place (19,818) (19,818) (19,818) ------- ------- ------- Proved reserves end of year 6 6 6 =========== ========== ========== PROVED DEVELOPED RESERVES AT: December 31, 1995 6 6 6 January 1, 1995 8,385 8,385 8,385
S-21 55 (1) 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 above 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. (2) 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. (3) 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. (4) 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. (5) Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVE QUANTITIES (UNAUDITED) The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS No. 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. S-22 56 The standardized measure of discounted future net cash flows as of December 31, 1997 was calculated using prices in effect at December 31, 1997, which averaged $9.92 per Bbl. Had the standardized measure of discounted future net cash flows been calculated using the average prices in effect on March 25, 1998, of $7.94 per Bbl, the standardized measure of discounted future net cash flows would have been approximately $252.5 million. GEOILBENT received a waiver from the export tariff assessed on all oil produced in and exported from Russia for 1995. The discounted value of the waiver net to the Company's interest as of December 31, 1994 was approximately $3 million. In July 1996, such oil export tariffs were terminated in conjunction with a loan agreement with the International Monetary Fund. 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. STANDARDIZED MEASURE
MINORITY UNITED INTEREST IN VENEZUELA RUSSIA STATES TOTAL VENEZUELA NET TOTAL -------------------------------------------------------------------------------------- (amounts in thousands) 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 =========== ========= =========== ========= =========== DECEMBER 31,1995 Future cash inflow $ 652,110 $ 283,630 $ 19 $ 935,759 $(130,422) $ 805,337 Future production costs (170,328) (102,783) (2) (273,113) 34,066 (239,047) Other related future costs (76,368) (36,686) 0 (113,054) 15,274 (97,780) ----------- --------- ------------ ----------- --------- ----------- Future net revenue before income taxes 405,414 144,161 17 549,592 (81,082) 468,510 10% annual discount for estimated timing of cash flows (118,498) (58,800) (1) (177,299) 23,700 (153,599) ----------- --------- ------------ ----------- --------- ----------- Discounted future net cash flows before income taxes 286,916 85,361 16 372,293 (57,382) 314,911 Future income taxes, discounted at 10% per annum (80,371) (29,927) 0 (110,298) 16,074 (94,224) ----------- --------- ------------ ----------- --------- ----------- Standardized measure of discounted future net cash flows $ 206,545 $ 55,434 $ 16 $ 261,995 $ (41,308) $ 220,687 =========== ========= ============ =========== ========= ===========
S-23 57
YEARS ENDED DECEMBER 31, -------------------------------------- CHANGES IN STANDARDIZED MEASURE 1997 1996 1995 --------- --------- --------- (amounts in thousands) Balance, January 1 $ 396,973 $ 261,995 $ 223,387 Changes resulting from: Sales of oil and gas, net of related costs (122,179) (121,954) (52,170) Revisions to estimates of proved reserves: Pricing (102,357) 108,705 (6,990) Quantities 82,211 (56,315) (63,802) Sales of reserves in place (18) (28,102) Extensions, discoveries and improved recovery, net of future costs 25,725 183,968 170,037 Accretion of discount 53,756 37,230 33,632 Change in income taxes 53,756 (30,288) 2,635 Development costs incurred 61,207 63,013 47,657 Changes in timing and other (94,188) (49,363) (64,289) --------- --------- --------- Balance, December 31 $ 354,904 $ 396,973 $ 261,995 ========= ========= =========
NOTE 19 - 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, 1997 Revenues $46,299 $40,977 $45,188 $46,555 Expenses 28,966 30,418 36,603 41,173 ------- ------- ------- ------- Income before incomes taxes and minority interest 17,333 10,559 8,585 5,382 Income taxes 5,984 4,432 4,492 2,569 ------- ------- ------- ------- 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
S-24 58
QUARTER ENDED --------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- -------- ------------ ----------- (amounts in thousands, except per share data) YEAR ENDED DECEMBER 31, 1996 Revenues $ 32,939 $41,890 $40,901 $49,336 Expenses 19,853 20,935 22,809 32,620 -------- ------- ------- ------- Income before incomes taxes and minority interest 13,086 20,955 18,092 16,716 Income taxes 4,449 4,992 6,401 4,666 -------- ------- ------- ------- 8,637 15,963 11,691 12,050 Minority interest 2,327 2,073 2,878 2,706 -------- ------- ------- ------- Income before extraordinary charge 6,310 13,890 8,813 9,344 Extraordinary charge for early retirement of debt, net of tax benefit 10,075 -------- ------- ------- ------- Net income $ 6,310 $ 3,815 $ 8,813 $ 9,344 ======== ======= ======= ======= Income per common share: Basic: Income before extraordinary charge $ 0.24 $ 0.52 $ 0.32 $ 0.33 Extraordinary charge (0.38) -------- ------- ------- ------- Net income $ 0.24 $ 0.14 $ 0.32 $ 0.33 ======== ======= ======= ======= Diluted: Income before extraordinary charge $ 0.22 $ 0.47 $ 0.29 $ 0.30 Extraordinary charge (0.34) -------- ------- ------- ------- Net income $ 0.22 $ 0.13 $ 0.29 $ 0.30 ======== ======= ======= =======
S-25 59 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 25th day of March, 1998. BENTON OIL AND GAS COMPANY ------------------------------------ (Registrant) Date: March 25, 1998 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 25th day of March, 1998, 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 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 EX-21.1 2 EXHIBIT 21.1 1 EXHIBIT 21.1 BENTON OIL AND GAS COMPANY LIST OF SUBSIDIARIES -------------------- JURISDICTION NAME OF INCORPORATION -------------------------------- ---------------------- Benton-Vinccler, C.A.* Venezuela Energy International Financial Institution, Ltd.* Cayman Islands Crestone Energy Corporation Colorado CEC Holding Company Delaware 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. EX-23.1 3 EXHIBIT 23.1 1 EXHIBIT 23.1 BENTON OIL AND GAS COMPANY INDEPENDENT AUDITORS' CONSENT ----------------------------- We consent to the incorporation by reference in Registration Statement Nos. 33-37124 on Form S-8, 33-70146 on Form S-3, 33-77946 on Form S-3, 333-135 on Form S-3, 333-17231 on Form S-3 and 333-19679 on Form S-8 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, 1997. Deloitte & Touche LLP Los Angeles, California March 27, 1998 EX-23.2 4 EXHIBIT 23.2 1 EXHIBIT 23.2 BENTON OIL AND GAS COMPANY INDEPENDENT PETROLEUM ENGINEERS' CONSENT Huddleston & Co., Inc., hereby consents to the use of its name in reference to it regarding its audit of the Benton Oil and Gas Company reserve reports, dated as of December 31, 1997, in the Form 10-K Annual Report of Benton Oil and Gas Company to be filed with the Securities and Exchange Commission. Peter D. Huddleston, P.E. Huddleston & Co., Inc. Houston, Texas March 25, 1998 EX-27.1 5 EXHIBIT 27.1
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K FOR THE PERIOD ENDED DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS YEAR DEC-31-1997 JAN-01-1997 DEC-31-1997 1 11,940 156,436 53,408 0 0 224,295 373,490 100,293 584,277 58,350 280,016 0 0 295 197,437 584,277 163,957 179,019 89,479 89,479 0 0 24,245 41,859 17,477 18,049 0 0 0 18,049 0.62 0.59
EX-27.2 6 EXHIBIT 27.2
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q FOR THE PERIOD ENDED MARCH 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS 3-MOS DEC-31-1997 JAN-01-1997 MAR-31-1997 1 41,450 45,058 61,645 0 0 153,733 279,819 62,548 445,460 47,654 176,554 0 0 290 184,281 445,460 43,476 46,299 17,992 17,992 0 0 5,485 17,333 5,984 8,628 0 0 0 8,628 0.30 0.28
EX-27.3 7 EXHIBIT 27.3
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q FOR THE PERIOD ENDED JUNE 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS 6-MOS DEC-31-1997 JAN-01-1997 JUN-30-1997 1 36,548 55,427 44,741 0 0 145,984 311,548 72,877 459,191 51,441 176,507 0 0 291 188,539 459,191 80,476 87,276 37,220 37,220 0 0 11,271 27,892 10,416 13,116 0 0 0 13,116 0.45 0.43
EX-27.4 8 EXHIBIT 27.4
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q FOR THE PERIOD ENDED SEPTEMBER 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS 9-MOS DEC-31-1997 JAN-01-1997 SEP-30-1997 1 32,955 51,159 52,406 0 0 142,875 344,064 85,487 478,096 64,891 176,489 0 0 292 192,504 478,096 121,869 132,464 62,540 62,540 0 0 16,726 36,477 14,908 15,985 0 0 0 15,985 0.55 0.52
EX-27.5 9 EXHIBIT 27.5
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q FORMTHE PERIOD ENDED MARCH 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS 3-MOS DEC-31-1996 JAN-01-1996 MAR-31-1996 1 7,804 0 34,427 0 0 64,198 195,646 27,715 234,893 61,472 46,050 0 0 261 117,735 234,893 31,285 32,939 11,805 11,805 0 0 2,260 13,086 4,449 6,310 0 0 0 6,310 0.24 0.22
EX-27.6 10 EXHIBIT 27.6
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q FOR THE PERIOD ENDED JUNE 30, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS 6-MOS DEC-31-1996 JAN-01-1996 JUN-30-1996 1 13,785 79,909 35,447 0 0 168,142 190,029 33,187 330,832 57,711 127,174 0 0 273 134,227 330,832 64,371 74,828 24,056 24,056 0 0 5,641 34,041 9,442 20,200 0 (10,075) 0 10,125 0.38 0.35
EX-27.7 11 EXHIBIT 27.7
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q FOR THE PERIOD ENDED SEPTEMBER 30, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS 9-MOS DEC-31-1996 JAN-01-1996 SEP-30-1996 1 22,647 74,130 44,016 0 0 142,192 213,050 41,131 387,971 52,023 175,031 0 0 277 146,315 387,971 102,417 115,729 38,083 39,083 0 0 10,776 52,133 15,843 29,013 0 (10,075) 0 18,938 0.71 0.64
EX-27.8 12 EXHIBIT 27.8
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K FOR THE PERIOD ENDED DECEMBER 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS YEAR DEC-31-1996 JAN-01-1996 DEC-31-1996 1 32,432 52,004 59,997 0 0 150,524 263,905 52,870 435,745 52,107 175,028 0 0 289 174,610 435,745 147,703 165,066 59,043 59,043 0 0 16,128 68,849 20,508 38,357 0 (10,075) 0 28,282 1.04 0.95
EX-27.9 13 EXHIBIT 27.9
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K FOR THE PERIOD ENDED DECEMBER 31, 1995 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 U.S. DOLLARS YEAR DEC-31-1995 JAN-01-1995 DEC-31-1995 1 6,180 0 24,939 0 0 51,648 179,650 19,982 214,750 54,535 49,486 0 0 255 103,426 214,750 62,157 65,068 28,114 28,114 1,673 0 7,497 18,373 2,478 10,591 0 0 0 10,591 0.42 0.41
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