<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(MARK ONE)
Annual Report Under Section 13 or 15(d)
of the Securities Exchange Act of 1934
[X] For the fiscal year ended December 31, 1998 or
Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from____________to_____________
COMMISSION FILE NO.: 1-10762
---------------------
BENTON OIL AND GAS COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
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DELAWARE 77-0196707
(STATE OR OTHER JURISDICTION OF INCORPORATION OR ORGANIZATION) (IRS Employer Identification Number)
6267 CARPINTERIA AVENUE, SUITE 200
CARPINTERIA, CALIFORNIA 93013
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
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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:
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ------------------- -----------------------------------------
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Common Stock, $.01 Par Value NYSE
Common Stock Purchase Warrants, $11.00 exercise price NASDAQ
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Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
On March 24, 1999, the aggregate market value of the shares of voting stock of
Registrant held by non-affiliates was approximately $104,882,872 based on a
closing sales price on NYSE of $3.63.
As of March 24, 1999, 29,576,966 shares of the Registrant's common stock were
outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 1999 Annual Meeting of
Stockholders to be filed with the Securities and Exchange Commission, not later
than 120 days after the close of its fiscal year, pursuant to Regulation 14A,
are incorporated by reference into Items, 10, 11, 12, and 13 of Part III of this
annual report.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.[X]
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BENTON OIL AND GAS COMPANY
FORM 10-K
TABLE OF CONTENTS
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Page
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Part I
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Item 1. Business.....................................................................3
Item 2. Properties..................................................................21
Item 3. Legal Proceedings...........................................................21
Item 4. Submission of Matters to a Vote of Security Holders ........................22
Part II
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Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters................................23
Item 6. Selected Consolidated Financial Data........................................24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................26
Item 7A. Quantitative and Qualitative Disclosures about
Market Risk....................................................32
Item 8. Financial Statements and Supplementary Data.................................33
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ........................33
Part III
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Item 10. Directors and Executive Officers of the Registrant .........................34
Item 11. Executive Compensation......................................................34
Item 12. Security Ownership of Certain Beneficial
Owners and Management..........................................34
Item 13. Certain Relationships and Related Transactions .............................34
Part IV
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Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................................35
Financial Statements.......................................................................37
Signatures.................................................................................66
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PART I
The Company cautions that any forward-looking statements (as such term is
defined in the Private Securities Litigation Reform Act of 1995) contained in
this report or made by management of the Company involve risks and uncertainties
and are subject to change based on various important factors. When used in this
report, the words budget, budgeted, anticipate, expect, believes, goals or
projects and similar expressions are intended to identify forward-looking
statements. In accordance with the provisions of the Private Securities
Litigation Reform Act of 1995, the Company cautions that important factors could
cause actual results to differ materially from those in the forward-looking
statements. Such factors include the Company's substantial concentration of
operations in Venezuela, the political and economic risks associated with
international operations, the anticipated future development costs for the
Company's undeveloped proved reserves, the risk that actual results may vary
considerably from reserve estimates, the dependence upon the abilities and
continued participation of certain key employees of the Company, the risks
normally incident to the operation and development of oil and gas properties and
the drilling of oil and gas wells, the price for oil and natural gas, and other
risks indicated in filings with the Securities and Exchange Commission. The
following factors, among others, in some cases have affected and could cause
actual results and plans for future periods to differ materially from those
expressed or implied in any such forward-looking statements: fluctuations in oil
and gas prices, changes in operating costs, overall economic conditions,
political stability, acts of terrorism, currency and exchange risks, changes in
existing or potential tariffs, duties or quotas, availability of additional
exploration and development opportunities, availability of sufficient financing,
changes in weather conditions, and ability to hire, retain and train management
and personnel.
ITEM 1. BUSINESS
GENERAL
Benton Oil and Gas Company (the "Company") is an independent energy company
which has been engaged in the development and production of oil and gas
properties since 1989. The Company has developed significant interests in
Venezuela and Russia, and has acquired certain interests in China, Jordan,
Senegal and the United States. The Company's producing operations are conducted
principally through its 80%-owned Venezuelan subsidiary, Benton-Vinccler, C.A.
("Benton-Vinccler"), which operates the South Monagas Unit in Venezuela, and its
34%-owned Russian joint venture, GEOILBENT, which operates the North Gubkinskoye
Field in West Siberia, Russia. The Company has expanded into projects which
involve exploration components in Russia through its ownership interest in
Severneftegaz; in China, through a farmout agreement with Shell Exploration
(China) Limited ("Shell") and the acquisition of the WAB-21 Exploration Block;
in Venezuela through its participation in the Delta Centro Exploration Block; in
both onshore and offshore Senegal; in the Sirhan Block in Southern Jordan; and
in Santa Barbara County, California through the acquisition of three state
offshore oil and gas leases.
As of December 31, 1998, the Company had total assets of $338.6 million, total
estimated proved reserves of 168.9 MMBOE, and a standardized measure of
discounted future net cash flow, before income taxes, for total proved reserves
of $112.0 million. For the year ended December 31, 1998, the Company had total
revenues of $112.1 million.
The Company was incorporated in Delaware in September 1988. Its principal
executive offices are located at 6267 Carpinteria Avenue, Suite 200,
Carpinteria, California 93013, and its telephone number is (805) 566-5600.
BUSINESS STRATEGY
The Company's business strategy is to identify and exploit new oil and gas
reserves primarily in under-developed but proven hydrocarbon regions thereby
seeking to minimize the associated risk of such activities. Specifically, the
Company endeavors to minimize risk by employing the following strategies in its
business activities: (i) seek new reserves primarily in areas of low geologic
risk; (ii) use proven advanced technology in both exploration and development to
maximize recovery, including the exploration of higher risk, higher potential
areas; (iii) establish a local presence through joint venture partners and the
use of local personnel; (iv) commit capital in a phased manner to limit total
commitments at any one time; and (v) reduce foreign exchange risks through
receipt of revenues in U.S. currency.
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SEEK NEW RESERVES IN AREAS OF LOW GEOLOGIC RISK. The Company has had significant
success in identifying under-developed reserves in the U.S. and internationally.
In particular, the Company has notable experience and expertise in seeking and
developing new reserves in countries where perceived potential political and
operating difficulties have sometimes discouraged other energy companies from
competing. As a result, the Company has established operations in Venezuela and
Russia, which have significant reserves that have been acquired and are being
developed at relatively low costs.
USE OF PROVEN ADVANCED TECHNOLOGY IN BOTH EXPLORATION AND DEVELOPMENT. The
Company's use of 3-D seismic technology, in which a three dimensional image of
the earth's subsurface is created through the computer interpretation of seismic
data, combined with its experience in designing the seismic surveys and
interpreting and analyzing the resulting data, allow for a more detailed
understanding of the subsurface than do conventional surveys. Such technology
contributes significantly to field appraisal, development and production. The
3-D seismic information, in conjunction with subsurface geologic data from
previously drilled wells, is used by the Company's experienced in-house
technical team to identify previously undetected reserves. The 3-D seismic
information can also be used to guide drilling on a real-time basis, and has
been especially helpful in the horizontal drilling done in Venezuela in order to
take advantage of oil-trapping faults.
ESTABLISH A LOCAL PRESENCE THROUGH JOINT VENTURE PARTNERS AND THE USE OF LOCAL
PERSONNEL. The Company has sought to establish a local presence where it does
business to facilitate stronger relationships with the local governments and
labor organizations through joint venture arrangements with local partners.
Moreover, the Company employs almost exclusively local personnel to run foreign
operations both to take advantage of local knowledge and experience and to
minimize cost. These efforts have created an expertise within Company management
in forming effective foreign partnerships and operating abroad. The Company
believes that it has gained access to new development opportunities as a result
of its reputation as a dependable partner.
COMMIT CAPITAL IN A PHASED MANNER TO LIMIT TOTAL COMMITMENTS AT ANY ONE TIME.
While the Company typically has agreed to a minimum capital expenditure or
development commitment at the outset of new projects, expenditures to fulfill
these commitments are phased over time. In addition, the Company seeks, where
possible, to use internally generated funds for further capital expenditures and
to invest in projects which provide the potential for an early return to the
Company.
REDUCE FOREIGN EXCHANGE RISKS. The Company seeks to reduce foreign currency
exchange risks by providing for the receipt of revenues in U.S. dollars while
most operating costs are incurred in local currency. Pursuant to the operating
service agreement between Benton-Vinccler and Lagoven, S. A., then one of three
exploration and production affiliates of the national oil company Petroleos de
Venezuela, S.A. which have subsequently all been combined into PDVSA Petroleo y
Gas, S.A. (all such parent, subsidiary and affiliated entities hereinafter
referred to as "PDVSA"), the operating fees earned by Benton-Vinccler are paid
directly to Benton-Vinccler's bank account in the United States in U.S. dollars.
GEOILBENT receives revenues from export sales in U.S. dollars paid to its
account in Moscow. As the Company continues to expand internationally, it will
seek to establish similar arrangements for new operations.
PRINCIPAL AREAS OF ACTIVITY
The following table summarizes the Company's proved reserves, drilling and
production activity, and financial operating data by principal geographic area
at and for each of the years ended December 31:
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VENEZUELA (1) RUSSIA (2)
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(dollars in 000's) 1998 1997 1996 1998 1997 1996
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RESERVE INFORMATION:
Proved Reserves (MBOE) 137,835 94,671 86,076 31,053 26,113 23,544
Discounted Future Net Cash
Flow Attributable to Proved
Reserves, Before Income
Taxes $ 62,455 $364,038 $446,854 $ 49,546 $77,696 $90,705
Standardized Measure of Future
Net Cash Flows $ 62,455 $291,471 $323,550 $43,248 $63,433 $73,423
DRILLING AND PRODUCTION ACTIVITY:
Gross Wells Drilled 16 27 33 31 7 5
Average Daily Production (BOE) 33,349 42,178 34,557 2,530 2,411 2,091
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VENEZUELA (1) RUSSIA (2)
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(dollars in 000's) 1998 1997 1996 1998 1997 1996
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FINANCIAL DATA:
Oil and Gas Revenues $ 82,215 $154,119 $136,840 $8,059 $9,925 $9,047
Expenses:
Lease Operating Costs and
Production Taxes 39,069 34,516 17,669 5,626 7,349 6,605
Depletion 31,843 43,584 29,523 2,474 3,079 2,747
Write down of oil and gas
properties 187,811 - - 10,100 - -
Income tax expense (benefit) (26,793) 25,656 24,429 - - -
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Total Expenses 231,930 103,756 71,621 18,200 10,428 9,352
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Results of Operations from
Oil and Gas Producing
Activities $(149,715) $50,363 $65,219 $ (10,141) $ (503) $ (305)
========= ======= ======= ========= ====== ======
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[FN]
(1) Includes 100% of the reserve information, drilling and production activity
and financial data, without deduction for minority interest. All Venezuelan
reserves are attributable to an operating service agreement between
Benton-Vinccler and PDVSA under which all mineral rights are owned by the
Government of Venezuela. See "--South Monagas Unit, Venezuela."
(2) The financial information for Russia includes the Company's 34% share of
the information for the twelve months ended September 30, 1996, 1997 and
1998, the end of the fiscal period for GEOILBENT.
</FN>
SOUTH MONAGAS UNIT, VENEZUELA
GENERAL
In July 1992, the Company and Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), a Venezuelan construction and engineering company,
signed a 20-year operating service agreement with PDVSA to reactivate and
further develop the Uracoa, Tucupita and Bombal Fields, which are a part of the
South Monagas Unit (the "Unit"). At that time, the Company was one of three
foreign companies ultimately awarded an operating service agreement to
reactivate existing fields by PDVSA, and was the first U.S. company since 1976
to be granted such an oil field development contract in Venezuela.
The oil and gas operations in the Unit are conducted by Benton-Vinccler, the
Company's 80%-owned subsidiary. The remaining 20% of the outstanding capital
stock of Benton-Vinccler is owned by Vinccler. The Company, through its majority
ownership of stock in Benton-Vinccler, makes all operational and corporate
decisions related to Benton-Vinccler, subject to certain super-majority
provisions of Benton-Vinccler's charter documents related to mergers,
consolidations, sales of substantially all of its corporate assets, change of
business and similar major corporate events. Vinccler has an extensive operating
history in Venezuela. It provided Benton-Vinccler with initial financial
assistance and continues to provide ongoing assistance with construction
services and governmental and labor relations.
Under the terms of the operating service agreement, Benton-Vinccler is a
contractor for PDVSA and is responsible for overall operations of the Unit,
including all necessary investments to reactivate and develop the fields
comprising the Unit. The Venezuelan government maintains full ownership of all
hydrocarbons in the fields. In addition, PDVSA maintains full ownership of
equipment and capital infrastructure following its installation. Benton-Vinccler
invoices PDVSA each quarter based on Bbls of oil accepted by PDVSA during the
quarter, using quarterly adjusted contract service fees per Bbl, and receives
its payments from PDVSA in U.S. dollars deposited directly into a U.S. bank
account. The operating service agreement provides for Benton-Vinccler to receive
an operating fee for each Bbl of crude oil delivered and a capital recovery fee
for certain of its capital expenditures, provided that such operating fee and
capital recovery fee cannot exceed the maximum total fee per Bbl set forth in
the agreement. The operating fee is subject to periodic adjustments to reflect
changes in the special energy index of the U.S. Consumer Price Index, and the
maximum total fee is subject to periodic adjustments to reflect changes in the
average of certain world crude oil prices. Since commencement of operations, the
Company has received approximately $11 million in capital recovery fees. Based
on crude oil prices as of December 31, 1998, the maximum total fee provided for
no capital recovery. The Company cannot predict the extent to which future
maximum total fee adjustments will provide for capital recovery components in
the fees it receives, and has recorded no asset for future capital recovery
fees.
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LOCATION AND GEOLOGY
The Unit extends across the southeastern part of the state of Monagas and the
southwestern part of the state of Delta Amacuro in eastern Venezuela. The Unit
is approximately 51 miles long and eight miles wide and consists of 157,843
acres, of which the fields comprise approximately one-half. At December 31,
1998, proved reserves attributable to the Company's Venezuelan operations were
137,835 MBOE, which represented approximately 82% of the Company's proved
reserves. Benton-Vinccler is currently developing the Oficina sands in the
Uracoa Field, which contain 84% of the Unit's proved reserves and has begun the
development of the Tucupita and Bombal Fields which contain the remaining 16% of
the Unit's reserves. The associated natural gas produced at Uracoa is currently
being reinjected into the field, as no ready market exists for the natural gas.
DRILLING AND DEVELOPMENT ACTIVITY
Uracoa Field
Benton-Vinccler has been developing the South Monagas Unit since 1992, beginning
with the Uracoa Field. During March 1999 (through March 24), a total of
approximately 93 wells were producing an average of approximately 22,184 Bbls of
oil per day in the Uracoa Field. The following table sets forth the Uracoa Field
drilling activity and production information for each of the quarters presented:
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WELLS DRILLED
---------------------------------- AVERAGE DAILY
VERTICAL HORIZONTAL PRODUCTION FROM FIELD (BBL)
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1996:
First Quarter 1 8 29,600
Second Quarter 5 4 33,700
Third Quarter 2 7 37,700
Fourth Quarter 1 4 37,500
1997:
First Quarter 2 6 36,100
Second Quarter 4 4 35,800
Third Quarter 1 6 40,500
Fourth Quarter 1 2 44,400
1998:
First Quarter - - 37,700
Second Quarter - - 32,600
Third Quarter 2 - 26,500
Fourth Quarter 3 3 25,900
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Daily production rates declined during the year due to a combination of
production problems and deferred drilling in the fourth quarter of 1997 and
first half of 1998. Drilling operations were deferred until production problems
in certain wells were identified and resolved. Without continuous drilling, a
mature field such as Uracoa experiences natural production declines. The natural
declines were aggravated during 1998 due to the impact of the production
problems on certain wells. Solutions to production problems were identified in
1998, but remediation will require work continuing into 1999. Additionally, the
Company focused its efforts on the completion of a detailed geologic and
reservoir simulation study during 1998. Drilling resumed in the second half of
1998, but the pace of drilling has been constrained due to uncertainties in oil
prices and cash flows.
Benton-Vinccler contracts with third parties for drilling and completion of
wells. Currently, Helmerich & Payne International Drilling Co. is performing
drilling services for Benton-Vinccler. The Company's technical personnel
identify drilling locations, specify the drilling program and equipment to be
used and monitor the drilling activities. To date, 15 previously drilled wells
have been reactivated and 100 new wells have been drilled in the Uracoa Field
using modern drilling and completion techniques that had not previously been
utilized on the field. Ninety-nine wells, or 99%, have been completed and placed
on production, and five injection wells have been drilled and six other wells
converted to injectors.
In December 1993, Benton-Vinccler drilled the first horizontal well in the
Uracoa Field. Since the completion of this well, the Company has successfully
integrated modern technology and modern drilling and completion techniques to
improve the ultimate recovery. The Company has conducted a 3-D seismic survey
and interpreted the seismic data over the Uracoa
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Field. As a horizontal well is drilled, information regarding formations
encountered by the drill bit is transmitted to the Company. Geologists,
engineers and geophysicists at the Company can determine the location of the
drill bit by comparing the information about the formations being drilled with
the 3-D seismic data. The Company then directs the movement of the drill bit to
more accurately direct the well to the expected reservoir.
The Company is in the process of completing a geologic and reservoir simulation
study with advanced analytical software and new core data. The geologic and
reservoir simulation study indicates the viability of at least 80 additional
primary infill wells in the Uracoa Field. Based on these results, approximately
80 new well locations have been identified in the Uracoa Field. Many of theses
new locations are in underdeveloped sands where the model was used to optimize
well spacing and location. In the more developed sands, the model was used to
verify the economic viability of infill locations. Timing of the drilling of the
additional well locations will depend on the Company's ability to generate
sufficient cash flow from operations or to obtain additional funding from other
sources.
Oil produced in the Uracoa Field is transported to production facilities which
were designed in the United States and installed by Benton-Vinccler. These
production facilities are of the type commonly used in heavy oil production in
the United States, but not previously used extensively in Venezuela to process
crude oil of similar gravity or quality. The current production facilities have
the capacity to process 60 MBbls of oil per day.
Tucupita and Bombal Fields
Before becoming inactive in 1987, the Tucupita Field had been substantially
developed, producing 67.1 MMBbls of oil, 34.7 MMBbls of water and 17.6 Bcf of
natural gas. Benton-Vinccler drilled a successful pilot well in late 1996 to
evaluate the remaining development potential of the Tucupita Field. This well
has produced at an approximate average rate of 1,896 Bbls of oil per day and
22,416 Bbls of water per day through December 1998.
In 1998, initial oil rates from the horizontal wells were encouraging, but water
cuts soon increased sharply. As a result, the redevelopment strategy was changed
to include drilling deviated wells to allow for more effective water shut-off.
The seven new deviated wells drilled in 1998 targeted underdeveloped portions of
the field. Additionally, four old wells have been reactivated, bringing current
production levels to 5.5 MBbls of oil per day.
Produced water from Tucupita is reinjected into the aquifer to aid the natural
water drive, while produced gas is being flared. The oil is trucked back to the
Uracoa facilities where it is processed and shipped by pipeline to the sales
point.
Eleven new well locations have been identified in underdeveloped portions of the
Tucupita Field, and additional viable wells are anticipated once a simulation
study is completed for Tucupita. Moreover, analysis of petrophysical and
production data has revealed significant behind-pipe recompletion potential in a
deeper pay section that was not a primary target during the earlier development
of the field. Currently, 15 wells with recompletion potential have been
identified for reactivation. A combination of horizontal, deviated and vertical
wells will be drilled to exploit the remaining oil reserves. Benton-Vinccler's
1999 capital expenditure budget includes the drilling of one well at an
estimated cost of $0.8 million. The drilling of additional wells will depend on
the Company's ability to generate sufficient cash flow from operations or to
obtain additional funding from other sources.
Given the results of the geologic and reservoir simulation study,
Benton-Vinccler continues to analyze alternatives for barging the oil and for
installing a pipeline from the Tucupita Field to the Uracoa Field. The
prospective pipeline would also be used for production from the Bombal Field
when it is developed. To date, the Company has drilled 1 well in the Bombal
Field and reactivated another, resulting in current combined production of 750
Bbls of oil per day. Future plans include further development of the Bombal
Field by drilling an additional evaluation well, at an anticipated cost of up to
$1 million, the timing of which will be dependent upon operational
considerations and the availability of funding.
CUSTOMERS AND MARKET INFORMATION
Oil produced in Venezuela is delivered to PDVSA under the terms of an operating
service agreement for an operating service fee. Benton-Vinccler has constructed
a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA's
storage facility, which is the custody transfer point. The service agreement
specifies that the oil stream may contain no more than 1% base sediment and
water, and quality measurements are conducted both at Benton-Vinccler's
facilities and at PDVSA's storage facility. A continuous flow measuring unit is
installed at Benton-Vinccler's facility, so that quantity is monitored
constantly. PDVSA provides Benton-Vinccler with a daily acknowledgment regarding
the amount of oil accepted the previous day, which is reconciled to
Benton-Vinccler's measurement. At the end of each quarter, Benton-Vinccler
prepares an invoice to PDVSA for that quarter's deliveries. PDVSA pays the
invoice at the end of the second month after the end of the quarter. Invoice
amounts and payments are denominated in U.S. dollars. Payments are wire
transferred into Benton-Vinccler's account in New York.
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EMPLOYEES; COMMUNITY RELATIONS
Benton-Vinccler seeks to employ nationals rather than bring expatriates into the
country. Presently, there are 12 full-time expatriates working with
Benton-Vinccler and 165 local employees. Benton-Vinccler also conducts community
relations programs, providing medical care, training, equipment and supplies,
and support for local schools, in both states in which the Unit falls.
DELTA CENTRO BLOCK, VENEZUELA
GENERAL
In January 1996, the Company and its bidding partners, Louisiana Land and
Exploration, which has been subsequently acquired by Burlington Resources Inc.
("Burlington"), and Norcen Energy Company, which has been subsequently acquired
by Union Pacific Resources Group Inc. ("UPR"), were awarded the right to explore
and develop the Delta Centro Block in eastern Venezuela. The contract requires a
minimum exploration work program consisting of completing a 550 square kilometer
3-D and a 289 kilometer 2-D seismic survey and drilling three wells to depths of
12,000 to 18,000 feet within five years. PDVSA estimated that this minimum
exploration work program would cost $60.0 million, and required that the
partners each post a performance surety bond or standby letter of credit for its
pro rata share of the estimated work commitment expenditures. The Company
provided a standby letter of credit in the amount of $18.0 million. The Company
has a 30% interest in the exploration venture, with the other partners each
owning a 35% interest. Under the terms of the operating agreement, which
establishes the management company for the project, Burlington is the operator
of the block, and therefore the Company does not exercise control of the
operations of the venture. It is currently anticipated that Corporacion
Venezolana del Petroleo, S.A. ("CVP"), an affiliate of PDVSA, will have a 35%
interest in the management company, which will dilute the voting power of the
partners on a pro rata basis.
If areas within the block are deemed to be commercially viable, then the group
has the right to enter into further agreements with CVP to develop those areas
during the next 20-25 years. CVP would participate in the revenues and costs
with an interest between 1 and 35%, at CVP's discretion. Any oil and gas
produced by the Delta Centro consortium will be sold at market prices and will
be subject to the oil and gas taxation regime in Venezuela and to the terms of a
profit sharing agreement with PDVSA. Under the current oil and gas tax law, a
royalty of up to 16.66% will be paid to the state. Under the contract bid terms,
41% of the pre-tax income will be shared with PDVSA for the period during which
the first $1.0 billion of revenues is produced; thereafter, the profit sharing
amount may increase to up to 50% according to a formula based on return on
assets. Currently, the statutory income tax rate for oil and gas enterprises is
67.7%. Royalties and shared profits are currently deductible for tax purposes.
LOCATION AND GEOLOGY
The Delta Centro Block consists of approximately 2,100 square kilometers
(526,000 acres) located in the delta of the Orinoco River 12 miles north of
South Monagas. Although no significant exploratory activity had previously been
conducted on the block prior to being made available for bids in 1995, PDVSA
estimated that the area may contain recoverable oil reserves of as much as 820
MMBbls, and may be capable of producing up to 160 MBbls of oil per day. The
general area of Venezuela in which the Delta Centro Block is located is known to
be a significant source of hydrocarbons, evidenced by the Orinoco tar sands to
the south and the El Furrial light oil trend to the northwest. Based on its
geological studies of the basins in this area, the Company's technical staff
believes that hydrocarbons have essentially migrated over time from the deeper
Maturin Basin area of Venezuela southward toward the shallower Orinoco tar belt
area. If so, then potential trapping structures and/or faults in the path of the
migrating oil would serve as traps for the migrating oil and have the
opportunity to be filled to their spill points. Delta Centro is directly in line
with this migration path, making it an attractive exploration area. The area is
mostly swampy in nature, with terrain ranging from forest in the north to
savannah in the south. The marshlands in the block are similar to the transition
zone areas in the Gulf of Mexico in which the Company has significant experience
in seismic and drilling operations.
DRILLING AND DEVELOPMENT ACTIVITY
The venture has acquired a 595 square kilometer 3-D seismic survey over the
southwestern portion of the Delta Centro Block and a 371 kilometer 2-D seismic
survey to evaluate the remaining exploration potential of the block, at an
expected total cost to the Company of approximately $8.3 million, of which $6.8
million had been spent through December 31, 1998. During the first quarter of
1999, drilling commenced on the Jarina 1-X, the first of the block's exploration
wells, with a total anticipated cost
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to the Company of $5.6 million. The well has a planned total depth of 15,600
feet and will take approximately 90 days to drill. As of December 31, 1998, the
Company had incurred total capital expenditures of $8.2 million related to the
block.
COMMUNITY AND COUNTRY RELATIONS
The Company conducts a community relations program in the area, providing
medical care, equipment and supplies to the Warao tribe which resides in this
area.
NORTH GUBKINSKOYE, RUSSIA
GENERAL
In December 1991, the joint venture agreement forming GEOILBENT among the
Company (34% interest) and two Russian partners, Purneftegazgeologia and
Purneftegaz (each having a 33% interest), was registered with the Ministry of
Finance of the USSR. In November 1993, the agreement was registered with the
Russian Agency for International Cooperation and Development. Although GEOILBENT
may only take action through the unanimous vote of the partners, the Company
believes that it has developed a good relationship with its partners and has not
experienced any disagreement with its partners on major operational matters. Mr.
A.E. Benton, Chief Executive Officer of the Company, has consistently been
elected Chairman of the general shareholders meetings since inception of
GEOILBENT.
LOCATION AND GEOLOGY
GEOILBENT develops, produces and markets crude oil from the North Gubkinskoye
Field in the West Siberia region of Russia, located approximately 2,000 miles
northeast of Moscow. The field, which covers an area approximately 15 miles long
and 4 miles wide, has been delineated with over 60 exploratory wells (which
tested 26 separate reservoirs) and is surrounded by large proven fields. Before
commencement of GEOILBENT's operations, the North Gubkinskoye Field was one of
the largest oil and gas fields in the region not under commercial production.
The field is a large anticlinal structure with multiple pay sands. The
development to date has focused on the BP 8, 9, 10, 11 and 12 reservoirs with
minor development in the BP 7 reservoir. The produced natural gas is currently
being flared in accordance with environmental regulations.
DRILLING AND DEVELOPMENT ACTIVITY
GEOILBENT commenced initial operations in the field during the third quarter of
1992 with the construction of a 37-mile oil pipeline and installation of
temporary production facilities. During March 1999 (through March 24),
approximately 62 wells were producing an average of approximately 10.8 MBbls of
oil per day. The following table sets forth drilling activity and production
information for each of the quarters presented:
<TABLE>
<CAPTION>
AVERAGE DAILY
WELLS DRILLED PRODUCTION FROM FIELD
------------- ---------------------
<S> <C> <C>
1996:
First Quarter 4 8,400
Second Quarter 1 7,200
Third Quarter - 7,100
Fourth Quarter - 6,500
1997:
First Quarter 1 6,300
Second Quarter 2 6,800
Third Quarter 1 6,800
Fourth Quarter 3 6,600
1998:
First Quarter 10 7,600
Second Quarter 9 8,600
Third Quarter 7 10,000
Fourth Quarter 5 9,900
</TABLE>
<PAGE> 10
10
GEOILBENT contracts with third parties for drilling and completion of wells.
Supervised by a joint American and Russian management team, GEOILBENT identifies
drilling locations, then uses Russian drilling rigs, upgraded by certain western
technology and materials, to drill and complete a well. To date, 15 previously
drilled wells have been reactivated and 89 wells have been drilled in the field,
with 69 wells, or 78%, completed and placed on production. Four drilling rigs
are currently working on various pads in the field. Each well is drilled to an
average depth of approximately 9,000 feet measured depth and 8,000 feet true
vertical depth.
Oil produced from the North Gubkinskoye Field is transported to production
facilities constructed and owned by GEOILBENT. Oil is then transferred to
GEOILBENT's 37-mile pipeline which transports the oil from the North Gubkinskoye
Field south to the main Russian oil pipeline network.
The current production facilities are operating at or near capacity and will
need to be expanded to accommodate production increases. GEOILBENT has obtained
financing through a $65 million parallel loan facility (the "EBRD Credit
Facility") for the development of the North Gubkinskoye Field from the European
Bank for Reconstruction and Development (the "EBRD") and International Moscow
Bank ("IMB"). $19 million has been advanced from the EBRD Credit Facility as of
December 31, 1998 and in March 1999, GEOILBENT borrowed an additional 8.3
million. Additional borrowing will be based on achieving certain reserve and
production milestones. GEOILBENT has a 1999 capital expenditure budget of
approximately $21 million, of which $10 million would be used to drill 32 wells
in the North Gubkinskoye Field and $11 million would be used for construction of
production facilities. This budget will be dependent upon increased availability
to draw from the EBRD Credit Facility and cash flow from operations.
CUSTOMERS AND MARKET INFORMATION
GEOILBENT's 37-mile pipeline runs from the field to the main pipeline in the
area where GEOILBENT transfers the oil to Transneft, the state oil pipeline
monopoly. Transneft then transports the oil to the western border of Russia for
export sales or to various domestic locations for non-export sales. All export
oil sales are handled by trading companies such as Russoil or NAFTA Moscow. All
export sales have been paid in U.S. dollars into GEOILBENT's account in Moscow.
EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS
Having access to the oilfield labor base in West Siberia, GEOILBENT employs
Russian nationals almost exclusively. Presently, there are two full-time
expatriates working with GEOILBENT and 412 local employees. The Company has
conducted community relations programs in Russia, providing medical care,
training, equipment and supplies in towns in which GEOILBENT personnel reside
and also for the nomadic indigenous population which resides in the area of
oilfield operations.
ALTERNATIVES FOR NATURAL GAS RESERVES
The Company and GEOILBENT estimate that substantial recoverable associated gas
reserves exist in the North Gubkinskoye Field. In addition, there are
substantial non-associated natural gas reserves in the field. While associated
gas is currently flared in allowable amounts under permits with the Ministry of
Fuel and Energy, Geoilbent is moving forward with plans to sell such gas in the
local marketplace. Discussions are underway with Gazprom, the state natural gas
monopoly, for development, production and sales of both associated and
non-associated gas, which together are estimated by the Company to total
approximately 4.0 Tcf. First stage development of the North Gubkinskoye gas
reserves would likely involve construction of a natural gas pipeline from the
field to the local gas processing plant, as well as possible expansion of that
plant. Preliminary analysis indicates that Geoilbent's first year capital
investment in such projects could be about $10.0 million.
EAST URENGOY, RUSSIA
GENERAL
Severneftegaz was formed in 1992 as a private company to explore and develop the
Samburg and Yevo-Yakha License Blocks, which are located in the prolific Urengoy
gas province of West Siberia. Under the terms of the Cooperation Agreement
signed in March 1998 ("Cooperation Agreement"), the Company acquired a 40%
interest in Severneftegaz in return for providing or arranging up to $100
million of credit financing for the project.
<PAGE> 11
11
The Cooperation Agreement imposes restrictions on the sale and transfer of the
initial 40% of Severneftegaz's shares acquired subject to disbursements under
the credit facility. It provides that for every $2.5 million of credit made
available to Severneftegaz, 1% of the Company's shares will be released from the
restrictions on sale and transfer. As of December 31, 1998, the Company had
provided $8.3 million of credit, of which approximately $5.6 million had been
applied to the release of restrictions on the shares. As a result, 2% of the
shares have been released from their restrictions. The Company, as the primary
owner, controls all of Severneftegaz's expenditures, budgeting and financial
planning. The Company increased its equity position to 47.5% in December 1998
and to 55% in January 1999, through additional stock acquisitions which were not
part of the cooperation agreement and were not subject to any restrictions.
LOCATION AND GEOLOGY
The Samburg and Yevo-Yakha License Blocks comprise approximately 823,000 acres
and are situated nearly 1,740 miles northeast of Moscow in the Yamal-Nenets
Autonomous Region of Russia. The towns and communities of Novy Urengoy, Samburg,
Urengoy and Nyda are located near the two licenses. Extensive exploration
drilling and testing on the Samburg and Yevo-Yakha licenses has resulted in the
discovery of major reserves of gas, condensate and oil. The primary reservoirs
of these fields are currently being produced in both the adjacent Urengoy Field
and Rospan Block. These reserves represent strategic resources for Russian
domestic energy in addition to being a high quality export product. Historic
production at the Urengoy Field is now on decline, and the undeveloped reserves
discovered on the adjacent Severneftegaz and Rospan Blocks are of interest to
Gazprom and Russia as replacement for the production that is being lost at
Urengoy.
The Samburg and Yevo-Yakha License Blocks are located within the West Siberian
Basin, the world's largest sedimentary basin, which contains nearly one third of
the world's proved and probable gas reserves. Both license blocks occur on the
eastern flank of the giant Urengoy gas field, which currently produces
hydrocarbons from reservoirs similar to those found in Samburg and Yevo-Yakha.
Based on geologic and geophysical studies as well as data from the 109
exploratory wells drilled to date, Russian reserve engineers estimate that
Severneftegaz' licenses contain approximately 17 Tcf of gas, 780 MMBbls of
condensate and 910 MMbls of oil in recoverable reserves.
DRILLING AND DEVELOPMENT ACTIVITY
The planning for a 13-well Samburg pilot development project is underway. The
pilot project calls for the drilling of 12 additional wells, utilization of
previously drilled well # 725, installation of gas processing facilities and
connection into the export pipeline system. Due to their proximity to the
Urengoy field and its existing infrastructure, both of Severneftegaz' blocks are
well situated for fast track development. Preliminary agreements are already in
place between Severneftegaz and Gazprom to allow access to existing gas and
condensate pipelines and facilities that could result in product sales to
European markets. The Severneftegaz blocks are located in the heart of
Urengoy/Yamburg producing and support infrastructure region. Natural gas export
trunklines are located 11 kilometers from the blocks. The blocks are also close
to railroads for possible liquids transportation.
The combination of Gazprom's shareholdings and excess trunkline capacity combine
to reduce transportation risk. With production from the giant Urengoy and
Yamburg Fields in decline, significant pipeline capacity is available on
Gazprom's transportation system. Gazprom, which is one of the Company's
strategic partners in Severneftegaz with its own 12% ownership, is actively
encouraging Severneftegaz to begin developing the Samburg Field. Discussions are
underway with Gazprom concerning the transportation of Severneftegaz's gas, as
well as with various parties concerning the export and marketing of the gas.
Actual development activities are subject to the Company's ability to provide or
arrange further funding.
WAB-21, SOUTH CHINA SEA
GENERAL
In December 1996, the Company acquired Benton Offshore China Company, formerly
Crestone Energy Corporation, a privately held company headquartered in Denver,
Colorado. Benton Offshore China Company's principal asset is a petroleum
contract with China National Offshore Oil Company ("CNOOC") for the WAB-21 area.
The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea,
with an option for an additional 1.0 million acres under certain circumstances.
<PAGE> 12
12
LOCATION AND GEOLOGY
The WAB-21 Contract Area (the "Contract Area") is located approximately 50 miles
east of the Dai Hung (Big Bear) Oil Field. The block is adjacent to British
Petroleum's recent giant gas discovery at Lan Tay (Red Orchid) and 100 miles
north of Exxon's Natuna Discovery. The Contract Area covers several similar
structural trends each with potential for large hydrocarbon reserves in possible
multiple pay zones.
The Contract Area is located northwest of Zengmu Basin (Offshore Sarawak), where
two Chinese institutions have already conducted geophysical seismic surveys.
Based on the multi-disciplinary data available from Zengmu Basin to the
southeast, East Natuna Basin to the south and southwest, and WAN'AN (Con Son)
Basin to the west and northwest there is substantial evidence of significant
hydrocarbon potential in the Contract Area.
POLITICAL CONSIDERATIONS AND RISKS
China's claim of ownership of the area results from China's discovery and
China's use and historic administration of the area. This claim also includes
third party and official foreign government recognition of China's sovereignty
and jurisdiction over the Contract Area.
The nearby Nansha Islands were formally placed under Chinese administration
during the Ming Dynasty (1368-1644 AD). In 1883, Germans were banned from
geologically surveying the area by the Qing court, based on Chinese sovereignty
over the region. Since the establishment of Chinese government jurisdiction over
the area several hundred years ago, the Nansha Islands have long been recognized
as being Chinese territory. Additionally, Russian and Vietnamese maps have
historically shown this area as Chinese. Significantly, even Vietnam recognized
China's sovereignty of the islands from 1956 until 1975. Vietnam's former
Premier Van Dong acknowledged China's Nansha Island sovereignty in a diplomatic
note in 1958.
In April 1994, a Chinese seismic survey ship was intercepted by Vietnamese boats
in the Contract Area while attempting to conduct seismic acquisition operations.
The Chinese ship returned to its port without commencing its seismic work
program. China subsequently denounced Vietnam's action.
Since 1994 China has maintained publicly that it is willing to discuss the joint
development of the Contract Area with the Vietnamese government. However,
Vietnam has granted exploration and development rights to parts of the Contract
Area to Conoco Inc. Recently, high level discussions between officials of CNOOC
and PetroVietnam have resulted in preliminary agreements on resolving
territorial disputes in nearby areas. Significant progress has been made in the
disputed Hainan Island/Gulf of Tonkin Area, and it is hoped that similar steps
will be taken to resolve the issues outstanding in the South China Sea.
Exploration activities in the area will be subject to the resolution of the
disputes. The Company has recorded no reserves attributable to this petroleum
contract.
DRILLING AND DEVELOPMENT ACTIVITY
Due to the sovereignty issues, the Company has been unable to pursue an
aggressive exploration program during phase one of the contract. As a result,
extensions have been obtained by the Company, with the current extension in
effect until June 2001. China and Vietnam are now engaged in discussions to
resolve the territorial dispute. The Company plans to acquire a 7,705-mile 2-D
seismic survey covering the entire block. This seismic survey will cost an
estimated $8 million and will enable a full evaluation of the potential for
hydrocarbon traps in advance of committing to the next phase. The petroleum
contract provides that once phase one is complete, an optional phase two may be
entered upon relinquishment of 25% of the block. The phase two exploration
commitment consists of an exploratory well drilled to 6,562 feet (2,000 meters)
for a minimum commitment of $2 million followed by a 10% relinquishment within
six months of completion of the well.
<PAGE> 13
13
QINGSHUI BLOCK, CHINA
GENERAL
In October 1997, the Company signed a farmout agreement with Shell Exploration
(China) Limited, ("Shell"), whereby the Company acquired a 50% participation
interest in Shell's Liaohe area onshore exploration project in northeast China.
Shell has entered into a petroleum contract with the China National Petroleum
Corporation ("CNPC") to explore and develop the deep rights in the Qingshui
Block, a 563 square kilometer area (approximately 140,000 acres) in the delta of
the Liaohe River. The deep rights are below 3,300 and 3,500 meters. The contract
requires a three-phase exploration program. Shell is the operator of the
project.
Pursuant to the petroleum contract, the first exploration period commenced
November 1, 1996. Pursuant to the terms of the contract, a nine-month study
phase required a work commitment to evaluate the deep potential of the block,
with an expected minimum expenditure of $3 million. During the remainder of the
first exploration phase and prior to November 1, 1999, Shell is required to
drill and complete one exploratory well to a depth of 4,500 meters, with a
minimum expenditure of $8 million. A two-year second exploration phase would
require Shell to drill and complete one exploratory well to 4,500 meters with a
minimum expenditure of $8 million. At the commencement of phase two, 10% of the
phase one contract area must be relinquished. A two-year third exploration phase
would require Shell to drill and complete one additional exploratory well to
4,500 meters with a minimum expenditure of $8 million. At the commencement of
the third exploration phase, 30% of the phase two contract area must be
relinquished. At the conclusion of each of the exploration phases, Shell will
elect whether or not to continue to the next exploration phase. Following any
exploration phase under the contract, the contract permits production from each
oil field identified in the exploration phase for a period of 15 years. CNPC has
the right to retain up to a 51% interest in the block and will pay none of the
costs of the initial three exploratory wells. CNPC will thereafter pay its
proportionate share of all development and operating costs in the block and will
receive its proportionate share of all production from the block, including
production from the initial three wells. Shell and the Company will therefore
receive at least an aggregate 49% interest in the production from the block and
will pay their proportionate share of all development and operating costs.
Pursuant to the farmout agreement between Shell and the Company, the Company
will have 50% of Shell's working interest in the block. In July 1998, the
Company paid to Shell 50% of Shell's prior investment in the Block, which was
approximately $4 million ($2 million to the Company). In addition, the Company
agreed to pay 100% of the first $8 million of the costs for the phase one
exploration period, and 100% of the first $8 million of phase two exploration
costs if the well is completed as a commercial producer. If a commercial well
does not result from the first phase, all subsequent costs will be shared
equally. If Shell and the Company perform each of the three phases, and assuming
that a commercial well results from phase one, the Company's maximum aggregate
capital commitment will be $22 million.
LOCATION AND GEOLOGY
The petroleum contract covers the deep rights in the Qingshui Block, a 563
square kilometer area located onshore in northeast China, in the delta area of
the Liaohe River, Liaoning Province. Shell's evaluation of the block is based on
comprehensive data enhancement and analysis, including core evaluation,
petrophysics and 2-D seismic reprocessing, 3-D seismic mapping and volume
interpretation, charge modeling and dynamic reservoir simulations.
DRILLING AND DEVELOPMENT ACTIVITY
The first well on the Qingshui block was spudded in January 1999. Drilling is
now under way on Qing-22 Deep, a fault block structure with several potential
reservoirs within the target depth of 12,000 to 14,000 feet. The prospect is
considered to be a relatively moderate risk exploratory play because of its well
defined structure, a proven, local hydrocarbon charge, reservoir penetrations
from nearby wells, and a seismic amplitude anomaly possibly attributable to the
presence of hydrocarbons.
Drilling is expected to take 90 days, with another 30 days for testing. If the
well is successful, it is anticipated that production from this well will begin
as soon as possible and that development will tie into the network of adjacent
facilities and pipelines.
<PAGE> 14
14
SANTA BARBARA COUNTY, CALIFORNIA
GENERAL
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy Company, LLC
("Molino Energy"), which held 100% of these leases. The project area covers the
Molino, Gaviota and Caliente Fields, located approximately 35 miles west of
Santa Barbara, California. In consideration of the 40% participation interest in
the leases, the Company became the operator of the project and paid 100% of the
first $3.7 million and 53% of the remainder of the costs of the first well
drilled on the block. During 1998, the 2199 #7 exploratory well was drilled to
the Gaviota anticline. Drill stem tests proved to be inconclusive or
non-commercial, and the well was temporarily abandoned for further evaluation.
The Company's share of the drilling and testing of the 2199 #7 well was $8.5
million. In November 1998, the Company entered into an agreement to acquire
Molino Energy's interest in the leases in exchange for the release of its joint
interest billing obligations of approximately $1.9 million. The agreement to
acquire Molino Energy's interest will be finalized upon the completion of
certain lot splits and the assignment of various permits and rights.
LOCATION AND GEOLOGY
The Company's operating interest covers three known fields located on three
adjacent state oil and gas leases off the central California coast. Each of
these leases covers approximately 4,000 acres. The Molino, Gaviota and Caliente
Fields have produced an aggregate of 363 Bcf of natural gas from subsea
completion in the Vaqueros formation, and the deeper, Sacate/Matilija formation
has produced 12 Bcf of natural gas from the Molino Field. In addition, the
Monterey formation has been penetrated from all of the gas wells, but has never
been produced. The Monterey formation is known as a prolific oil producer in
this area. The onshore drill site has immediate access to oil and gas pipelines.
DRILLING AND DEVELOPMENT ACTIVITY
The 2199 #7 exploratory well was drilled to the Gaviota anticline to test four
distinct sandstone intervals in the Vaqueros/Sespe, Alegria, Gaviota and
Sacate/Matilija formations. Two drill stem tests spanning 1,300 vertical feet of
the primary objective, the Sacate/Matilija, proved the presence of gas and
condensate in a "tight" sandstone reservoir. A drill stem test in the Gaviota
formation proved to be non-commercial. The well has been temporarily abandoned
while the Company studies the economic benefit of alternatives, which could
include hydraulic fracturing in the Sacate Matilija and/or a sidetrack to
exploit the less risky reserves in the shallower Vaqueros and Alegria
sandstones. If the Company does not pursue the project within a three-year
period, it must be offered back to Molino Energy on farmout terms to be
negotiated by the parties.
SIRHAN BLOCK, JORDAN
GENERAL
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with the Natural Resources Authority of Jordan
("NRA"), established by the Hashemite Kingdom of Jordan, to explore, develop,
and produce the Sirhan block in southeastern Jordan.
Under the terms of the PSA, the Company is obligated to make certain capital and
operating expenditures in a first phase and may elect to continue into
additional phases with minimum commitments as follows: $5.1 million in the first
exploration phase (2 years) to perform geological studies and expenses incurred
in drilling exploratory wells; $8 million in the second exploration phase (3
years) for seismic acquisitions, geological studies, and expenses incurred in
drilling exploratory wells; and $10 million in the third exploration phase (3
years) for seismic acquisitions, geological studies, and expenses incurred in
drilling exploratory wells. If the Company expends more than the minimum
expenditure in one phase, the excess expenditure will be credited against the
Company's minimum expenditure obligation during the next phase. In addition, the
Company will be entitled to recover all operating costs and expenses incurred.
<PAGE> 15
15
LOCATION AND GEOLOGY
The Sirhan Block in southeastern Jordan consists of approximately 1.2 million
acres (4,827 square kilometers). This block is located in the Sirhan Basin
adjacent to the Jordan-Saudi Arabia border. One existing well on the block
tested light oil at low rates and several additional wells encountered thick
zones with indications of gas that have not been tested.
DRILLING AND DEVELOPMENT ACTIVITY
During the first quarter of 1998, the Company reentered two wells and tested two
different reservoirs. The WS-9 and WS-10 wells did not result in the production
of commercial amounts of hydrocarbons. The Company will continue to reprocess
and remap seismic data and conduct geological studies on the remaining
prospectivity of the block.
SENEGAL, AFRICA
GENERAL
In December 1997, the Company was awarded a 45% working interest in the Thies
Block in the western portion of Senegal by the state oil company Societe des
Petroles du Senegal ("Petrosen"). The Company will serve as operator of the
block. In consideration of the grant of the 45% ownership, the Company has
agreed to pay 90% of the first $6 million of costs to install a pipeline and
drill two wells and, if the Company elects to proceed further, to pay 67.5% of
the next $6 million of costs for further exploration and development.
Thereafter, the Company's share of all costs and revenues will be 45%.
Additionally, the Company has obtained the exclusive right to evaluate
approximately 7.5 million acres of Senegal's entire near-offshore holdings,
which have been partitioned into six separate blocks. This includes the joint
area shared between Senegal and Guinea-Bissau and comprises portions of the Dome
Flore block. The Company will serve as operator of each of the six offshore
blocks and will have an 85% participating interest with the balance held by
Petrosen. The Company is obligated to spend $1 million to reprocess and evaluate
existing seismic data, after which it may elect to proceed with further
operations on any or all of the blocks.
LOCATION AND GEOLOGY
The one-million acre onshore Thies block is located immediately east of the
Sebikhotane Block, which has proven production from Maastrichtian sandstones.
Deeper pay potential on the block has been demonstrated by the Gadiaga #2 well,
which was drilled and tested by Petrosen in March of 1997. The six near-offshore
blocks include Dome Flore, one of several salt domes known to exist offshore
Senegal.
DRILLING AND DEVELOPMENT ACTIVITY
The Company is reprocessing 1,565 kilometers of 2-D seismic data on the Thies
Block prior to making a reinterpretation of the existing discoveries and
planning an exploration program. In the offshore areas, the Company is
reprocessing approximately 10,000 kilometers of 2-D seismic data out of a total
data set of 24,000 kilometers. Following an evaluation of this data set, the
Company will select certain blocks for further exploration activity.
<PAGE> 16
16
RESERVES
The following table sets forth information regarding estimates of proved
reserves at December 31, 1998 prepared by the Company and audited by Huddleston
& Co., Inc., independent petroleum engineers:
<TABLE>
<CAPTION>
CRUDE OIL AND CONDENSATE (MBBL)
--------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -----
<S> <C> <C> <C>
Venezuela(1) 75,636 62,199 137,835
Russia(2) 9,745 21,308 31,053
------ ------ ------
Total 85,381 83,507 168,888
====== ====== =======
</TABLE>
[FN]
(1) Includes 100% of the reserve information, without deduction for minority
interest. All Venezuelan reserves are attributable to an operating service
agreement between Benton-Vinccler and PDVSA, under which all mineral rights
are owned by the Government of Venezuela. See "--South Monagas Unit,
Venezuela."
(2) Although the Company estimates that there are substantial natural gas
reserves in the North Gubkinskoye Field, no natural gas reserves have been
recorded because of a lack of a ready market.
Estimates of commercially recoverable oil and gas reserves and of the future net
cash flows derived therefrom are based upon a number of variable factors and
assumptions, such as historical production from the subject properties,
comparison with other producing properties, the assumed effects of regulation by
governmental agencies and assumptions concerning future operating costs,
severance and excise taxes, export tariffs, abandonment costs, development costs
and workover and remedial costs, all of which may vary considerably from actual
results. All such estimates are to some degree speculative, and various
classifications of reserves are only attempts to define the degree of
speculation involved. For these reasons, estimates of the commercially
recoverable reserves of oil attributable to any particular property or group of
properties, the classification, cost and risk of recovering such reserves and
estimates of the future net cash flows expected therefrom, prepared by different
engineers or by the same engineers at different times may vary substantially.
The difficulty of making precise estimates is accentuated by the fact that 49%
of the Company's total proved reserves were undeveloped as of December 31, 1998.
Therefore, the Company's actual production, revenues, severance and excise
taxes, export tariffs, development expenditures, workover and remedial
expenditures, abandonment expenditures and operating expenditures with respect
to its reserves will likely vary from estimates, and such variances may be
material. Reserve estimates are not constrained by the availability of the
capital resources required to finance the estimated development and operating
expenditures.
In addition, actual future net cash flows will be affected by factors such as
actual production, supply and demand for oil, availability and capacity of
gathering systems and pipelines, changes in governmental regulations or taxation
and the impact of inflation on costs. The timing of actual future net revenue
from proved reserves, and thus their actual present value, can be affected by
the timing of the incurrence of expenditures in connection with development of
oil and gas properties. The 10% discount factor, which is required by the
Securities and Exchange Commission to be used to calculate present value for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
the oil and gas industry. Discounted present value, no matter what discount rate
is used, is materially affected by assumptions as to the amount and timing of
future production, which assumptions may and often do prove to be inaccurate.
For the period ending December 31, 1998, the Company reported $112.0 million of
discounted future net cash flows before income taxes from proved reserves based
on the Commission's required calculations.
<PAGE> 17
17
PRODUCTION, PRICES AND LIFTING COST SUMMARY
The following table sets forth by country net production, average sales prices
and average lifting costs of the Company for the years ended December 31, 1998,
1997 and 1996:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER
---------------------------------------------
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
VENEZUELA
Net Crude Oil Production (Bbls) 12,172,352 15,394,807 12,647,987
Average Crude Oil Sales Price ($ per Bbl) $ 6.75 $10.01 $10.82
Average Lifting Costs ($ per Bbl) $ 3.21 $2.24 $1.40
RUSSIA (1)
Net Crude Oil Production (Bbls) 923,602 880,148 765,137
Average Crude Oil Sales Price ($ per Bbl) $ 8.72 $11.28 $11.82
Average Lifting Costs ($ per Bbl) $ 6.09 $8.35 $8.63
</TABLE>
[FN]
(1) The presentation for Russia includes information for the twelve months
ended September 30, 1996, 1997 and 1998, the end of the fiscal period for
GEOILBENT.
</FN>
REGULATION
GENERAL
The Company's operations are affected by political developments and laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and costs. In
any country in which the Company may do business, the oil and gas industry
legislation and agency regulation is periodically changed for a variety of
political, economic, environmental and other reasons. Numerous governmental
departments and agencies issue rules and regulations binding on the oil and gas
industry, some of which carry substantial penalties for the failure to comply.
The regulatory burden on the oil and gas industry increases the Company's cost
of doing business.
VENEZUELA
Venezuela requires environmental and other permits for certain operations
conducted in oil field development, such as site construction, drilling, and
seismic activities. As a contractor to PDVSA, Benton-Vinccler submits capital
and operating budgets to PDVSA for approval. Capital expenditures to comply with
Venezuelan environmental regulations relating to the reinjection of gas in the
field and water disposal were $10.2 million in 1998 and are expected to be $6.2
million in 1999. Benton-Vinccler also submits requests for permits for drilling,
seismic and operating activities to PDVSA, which then obtains such permits from
the Ministry of Energy and Mines and Ministry of Environment, as required.
Benton-Vinccler is also subject to income, municipal and value added taxes, and
must file certain monthly and annual compliance reports to the national tax
administration and to various municipalities.
RUSSIA
GEOILBENT submits annual production and development plans, which include
information necessary for permits and approvals for its planned drilling,
seismic and operating activities, to local and regional governments and to the
Ministry of Fuel and Energy, Committee of Geology and Ministry of Economy.
GEOILBENT also submits annual production targets and quarterly export
nominations for oil pipeline transportation capacity to the Ministry of Fuel and
Energy. GEOILBENT is subject to customs, value added, and municipal and income
taxes. Various municipalities and regional tax inspectorates are involved in the
assessment and collection of these taxes. GEOILBENT must file operating and
financial compliance reports with several bodies, including the Ministries of
Fuel and Energy, Committee of Geology, Committee for Technical Mining
Monitoring, the Ministry of Ecology, and the State Customs Committee.
<PAGE> 18
18
DRILLING, ACQUISITION AND FINDING COSTS
During the years ended December 31, 1998, 1997 and 1996, the Company spent
approximately $111 million, $109 million and $108 million, respectively, for
acquisitions of leases and producing properties, development and exploratory
drilling, production facilities and additional development activities such as
workovers and recompletions.
The Company has drilled or participated in the drilling of wells as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------------------
1998 1997 1996
--------------------------- -------------------------- ---------------------------
GROSS NET GROSS NET GROSS NET
------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
WELLS DRILLED:
Exploratory:
Crude oil - - - - - -
Natural gas - - - - 1 .375
Dry holes - - - - - -
Development:
Crude oil 46 22.54 31 22.040 36 26.500
Natural gas - - - - - -
Dry holes - - 1 .340 - -
----------- ------------ ------------ ------------ ------------ ------------
TOTAL 46 22.54 32 22.380 37 26.875
=========== ============ ============ ============ ============ ============
AVERAGE DEPTH OF WELLS (FEET) 7,934 6,659 8,008
PRODUCING WELLS (1):
Crude Oil 159 97.300 124 78.960 113 74.300
Natural Gas - - - - - -
</TABLE>
[FN]
(1) The information related to producing wells reflects wells the Company
drilled, wells the Company participated in drilling and producing wells the
Company acquired.
</FN>
At March 24, 1999, the Company was participating in the drilling of 1 well in
Venezuela, 2 wells in Russia and 1 well in China.
All of the Company's drilling activities are conducted on a contract basis with
independent drilling contractors. The Company does not own any drilling
equipment.
From commencement of operations through December 31, 1998, the Company added,
net of production and property sales, approximately 168.9 MMBOE of proved
reserves through purchases of reserves-in-place, discoveries of oil and natural
gas reserves, extensions of existing producing fields and revisions of
previously estimated reserves, for which the finding costs were $2.17 per BOE.
The Company's estimate of future development costs for its undeveloped proved
reserves at December 31, 1998 was $1.70 BOE. The estimated future development
costs are based upon the Company's anticipated cost of developing its
non-producing proved reserves, which costs are calculated using historical costs
for similar activities.
<PAGE> 19
19
ACREAGE
The following table summarizes the developed and undeveloped acreage owned,
leased or under concession as of December 31, 1998.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------------------ -------------------------------
GROSS NET GROSS NET
-------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Venezuela 8,090 6,472 673,188 275,903
Russia 32,700 11,118 1,577,297 647,400
China 0 0 7,609,197 7,539,638
Jordan 0 0 1,192,752 1,192,752
Senegal 1,280 576 8,594,491 8,046,047
United States 0 0 18,100 18,100
------------- ------------- -------------- --------------
Total 42,070 18,166 19,665,025 17,719,840
============= ============= ============== ==============
</TABLE>
COMPETITION
The Company encounters strong competition from major oil and gas companies and
independent operators in acquiring properties and leases for exploration for
crude oil and natural gas. The principal competitive factors in the acquisition
of such oil and gas properties include the staff and data necessary to identify,
investigate and purchase such leases, and the financial resources necessary to
acquire and develop such leases. Many of the Company's competitors have
financial resources, staffs and facilities substantially greater than those of
the Company.
EMPLOYEES AND CONSULTANTS
At December 31, 1998, the Company had 75 employees augmented from time to time
with independent consultants, as required. Benton-Vinccler had 165 employees,
and GEOILBENT had 412 employees.
TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE
All Venezuelan reserves are attributable to an operating service agreement
between Benton-Vinccler and PDVSA, under which all mineral rights are owned by
the Government of Venezuela. With regard to Russian acreage, GEOILBENT has
obtained certain documentation from appropriate regulatory bodies in Russia
which the Company believes is adequate to establish GEOILBENT's right to
develop, produce and market oil and gas from the North Gubkinskoye Field in
Russia.
The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea,
with an option for another one million acres under certain circumstances, and
lies within an area which is the subject of a territorial dispute between the
People's Republic of China and Vietnam. Vietnam has executed an agreement on a
portion of the same offshore acreage with Conoco Inc. The territorial dispute
has existed for many years, and there has been limited exploration and no
development activity in the area under dispute. It is uncertain when or how this
dispute will be resolved, and under what terms the various countries and parties
to the agreements may participate in the resolution, although certain proposed
economic solutions currently under discussion would result in the Company's
interest being reduced.
At the time of acquisition of undeveloped acreage in the United States, the
Company conducts a limited title investigation. A title opinion from a qualified
law firm is obtained prior to drilling any given U.S. prospect. Title to
presently producing properties is investigated by a qualified law firm prior to
purchase. The Company believes its method of investigating the title to these
domestic properties is consistent with general practices in the oil and gas
industry and is designed to enable the Company to acquire title which is
generally considered to be acceptable in the oil and gas industry.
<PAGE> 20
20
GLOSSARY
When the following terms are used in the text they have the meanings indicated.
MCF. "Mcf" means thousand cubic feet. "Mmcf" means million cubic feet.
"Bcf" means billion cubic feet. "Tcf" means trillion cubic feet.
BBL. "Bbl" means barrel. "Bbls" means barrels. "MBbls" means thousand
barrels. "MMBbls" means million barrels. "BBbls" means billion barrels.
BOE. "BOE" means barrels of oil equivalent, which are determined using the
ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf
of natural gas so that six Mcf of natural gas is referred to as one barrel of
oil equivalent or "BOE". "MBOE" means thousands of barrels of oil equivalent.
"MMBOE" means millions of barrels of oil equivalent.
CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with
exploratory and development drilling (including exploratory dry holes);
leasehold acquisitions; seismic data acquisitions; geological, geophysical and
land-related overhead expenditures; delay rentals; producing property
acquisitions; and other miscellaneous capital expenditures.
COMPLETION COSTS. "Completion Costs" means, as to any well, all those costs
incurred after the decision to complete the well as a producing well. Generally,
these costs include all costs, liabilities and expenses, whether tangible or
intangible, necessary to complete a well and bring it into production, including
installation of service equipment, tanks, and other materials necessary to
enable the well to deliver production.
DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional
well to the same reservoir as other producing wells on a lease, or drilled on an
offset lease not more than one location away from a well producing from the same
reservoir.
EXPLORATORY WELL. An "Exploratory Well" is a well drilled in search of a
new and as yet undiscovered pool of oil or gas, or to extend the known limits of
a field under development.
FINDING COST. "Finding Cost", expressed in dollars per BOE, is calculated
by dividing the amount of total capital expenditures related to acquisitions,
exploration and development costs (reduced by proceeds for any sale of oil and
gas properties) by the amount of total net reserves added or reduced as a result
of property acquisitions and sales, drilling activities and reserve revisions
during the same period.
FUTURE DEVELOPMENT COST. "Future Development Cost" of proved nonproducing
reserves, expressed in dollars per BOE, is calculated by dividing the amount of
future capital expenditures related to development properties by the amount of
total proved non-producing reserves associated with such activities.
GROSS ACRES OR WELLS. "Gross Acres or Wells" are the total acres or wells,
as the case may be, in which an entity has an interest, either directly or
through an affiliate.
LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a
producing formation to the surface, consisting of the costs incurred to operate
and maintain wells and related equipment and facilities, including labor costs,
repair and maintenance, supplies, insurance, production, severance and windfall
profit taxes.
NET ACRES OR WELLS. A party's "Net Acres" or "Net Wells" are calculated by
multiplying the number of gross acres of gross wells in which that party has an
interest by the fractional interest of the party in each such acre or well.
PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved Developed
Reserves expected to be produced from existing completion intervals now open for
production in existing wells. "Producing Properties" are properties to which
Producing Reserves have been assigned by an independent petroleum engineer.
<PAGE> 21
21
PROVED DEVELOPED RESERVES. "Proved Developed Reserves" are Proved Reserves
which can be expected to be recovered through existing wells with existing
equipment and operating methods.
PROVED RESERVES. "Proved Reserves" are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known oil and gas reservoirs under existing economic and operating conditions,
that is, on the basis of prices and costs as of the date the estimate is made
and any price changes provided for by existing conditions.
PROVED UNDEVELOPED RESERVES. "Proved Undeveloped Reserves" are Proved
Reserves which can be expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion.
RESERVES. "Reserves" means crude oil and natural gas, condensate and
natural gas liquids, which are net of leasehold burdens, are stated on a net
revenue interest basis, and are found to be commercially recoverable.
ROYALTY INTEREST. A "Royalty Interest" is an interest in an oil and gas
property entitling the owner to a share of oil and gas production (or the
proceeds of the sale thereof) free of the costs of production.
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS. The "Standardized Measure of
Future Net Cash Flows" is a method of determining the present value of Proved
Reserves. The future net revenues from Proved Reserves are estimated assuming
that oil and gas prices and production costs remain constant. The resulting
stream of revenues is then discounted at the rate of 10% per year to obtain a
present value.
3-D SEISMIC. "3-D Seismic" is the method by which a three dimensional image
of the earth's subsurface is created through the interpretation of seismic data.
3-D surveys allow for a more detailed understanding of the subsurface than do
conventional surveys and contribute significantly to field appraisal,
development and production.
UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and gas acreage on which
wells have not been drilled or completed to a point that would permit commercial
production regardless of whether such acres contain proved reserves.
ITEM 2. PROPERTIES
The Company has entered into a 15 year lease agreement for office space in
Carpinteria, California. The Company has leased 50,000 square feet for
approximately $74,000 per month with annual rent adjustments based on certain
changes in the Consumer Price Index. The Company has entered into a sublease
agreement for the office space which will not be immediately needed for
operations. The Company has also entered into a sublease agreement for the
office space that it previously occupied. Rents for the subleases approximate
the Company's lease costs of these facilities. For information concerning the
location and character of the Company's oil and gas properties and interests,
see Item 1.
ITEM 3. LEGAL PROCEEDINGS
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties, and that it paid a
price in excess of the fair value of the property. A trial date has been
scheduled for August 9, 1999 and discovery is ongoing, but incomplete. The
Company intends to vigorously contest the suit, and in management's opinion it
is too early to assess the probability of an unfavorable outcome.
<PAGE> 22
22
On June 13, 1994, Charles Agnew and other limited partners in several limited
partnerships formed by the Company brought an action in the Superior Court of
California, County of Ventura, against the Company for alleged actions and
omissions of the Company in operating the partnerships and alleged
misrepresentations made by the Company in selling the limited partnership
interests. The claimants seek an unspecified amount of actual and punitive
damages. On May 17, 1995, the Company agreed to a binding arbitration proceeding
with respect to such claims. In January 1996, the Company acquired all of the
interests in three of the limited partnerships which were the subject of the
arbitration in exchange for shares of and warrants to purchase shares of the
Company's common stock. In an arbitration proceeding, if any liability is found
to exist, the arbitrator would determine the amount of any damages, and may
consider all distributions made to the partners, including the consideration
received in the exchange offer, in determining the extent of damages, if any.
However, there can be no assurance that an arbitrator would consider such
factors in his or her determination of damages if the allegations are found to
be true and damages are awarded. Based on the plaintiffs' failure to pursue the
arbitration, the American Arbitration Association dismissed the case on November
25, 1998, but gave the plaintiffs until February 23, 1999, to obtain a court
order compelling arbitration. To date, the plaintiffs have neither sought nor
obtained such a court order.
In the normal course of the Company's business, there are various other legal
proceedings outstanding. In the opinion of management, these proceedings will
not have a material adverse effect on the Company's financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the three month period ended December 31, 1998, no matter was submitted
to a vote of security holders.
<PAGE> 23
23
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Company's Common Stock is traded on the New York Stock Exchange ("NYSE")
under the symbol "BNO." For the period represented below, the Company's Common
Stock was traded on the NASDAQ Stock Market under the symbol "BNTN" until April
29, 1997, when the Company's Common Stock began trading on the NYSE. As of
December 31, 1998, there were 29,576,844 shares of Common Stock outstanding held
of record by approximately 1,064 stockholders. The following table sets forth
the high and low sales prices for the Company's Common Stock reported on the
NASDAQ from January 1, 1997 to April 28, 1997 and on the NYSE thereafter.
<TABLE>
<CAPTION>
YEAR QUARTER HIGH LOW
---- ------- ---- ---
<S> <C> <C> <C>
1997
First quarter $ 24.75 $ 14.63
Second quarter 17.13 12.63
Third quarter 19.25 13.50
Fourth quarter 21.88 11.25
1998
First quarter 13.69 9.75
Second quarter 13.50 7.38
Third quarter 10.75 4.69
Fourth quarter 6.25 2.44
</TABLE>
On March 24, 1999, the last sales price for the Common Stock as reported by NYSE
was $3.63 per share.
The Company's policy is to retain its earnings to support the growth of the
Company's business. Accordingly, the Board of Directors of the Company has never
declared cash dividends on its Common Stock. The Company's indentures currently
restrict the declaration and payment of any cash dividends.
<PAGE> 24
24
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data for the Company for each of
the five years in the period ended December 31, 1998, are derived from the
Company's audited consolidated financial statements. The consolidated financial
data below should be read in conjunction with the Company's Consolidated
Financial Statements and related notes thereto and Item 7. -- Management's
Discussion and Analysis of Financial Condition and Results of Operations
contained elsewhere in this report.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------------
1998 1997 1996 1995 (2) 1994
------------ ------------ ------------ ------------ ------------
(amounts in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS:
Total revenues $112,148 $179,019 $165,066 $ 65,068 $ 34,705
Lease operating costs and production taxes 44,675 41,887 24,518 10,703 9,531
Depletion, depreciation and amortization 35,638 47,592 34,525 17,411 10,298
Write-down and impairment of oil and gas properties
203,993 - - - -
General and administrative expense 25,629 23,436 18,906 9,411 5,242
Interest expense 32,908 24,245 16,128 7,497 3,888
Partnership exchange expenses - - 2,140 - -
Litigation settlement expenses - - - 1,673 -
--------- ------- ------- ------- -------
Income (loss) before income taxes, minority
interest and extraordinary charge (230,695) 41,859 68,849 18,373 5,746
Income tax expense (benefit) (24,220) 17,477 20,508 2,478 698
--------- ------- ------- ------- -------
Income (loss) before minority interest and
extraordinary charge (206,475) 24,382 48,341 15,895 5,048
Minority interest (22,895) 6,333 9,984 5,304 2,094
--------- ------- ------- ------- -------
Income (loss) before extraordinary charge (183,580) 18,049 38,357 10,591 2,954
Extraordinary charge for early retirement of
debt, net of tax benefit of $879 - - 10,075 - -
--------- ------- ------- ------- -------
Net income (loss) $(183,580) $18,049 $28,282 $10,591 $ 2,954
========= ======= ======= ======= =======
Net income (loss) per common share:
Basic:
Income (loss) before extraordinary
charge $ (6.21) $ 0.62 $ 1.42 $ 0.42 $ 0.12
Extraordinary charge - - 0.38 - -
--------- ------- ------- ------- -------
Net income (loss) $ (6.21) $ 0.62 $ 1.04 $ 0.42 $ 0.12
========= ======= ======= ======= =======
Diluted:
Income (loss) before extraordinary
charge $ (6.21) $ 0.59 $ 1.29 $ 0.40 $ 0.12
Extraordinary charge - - 0.34 - -
--------- ------- ------- ------- -------
Net income (loss) $ (6.21) $ 0.59 $ 0.95 $ 0.40 $ 0.12
========= ======= ======= ======= =======
Weighted average common shares outstanding
Basic 29,554 29,119 27,088 25,084 24,851
Diluted 29,554 30,834 29,813 26,673 25,325
</TABLE>
<PAGE> 25
25
<TABLE>
<CAPTION>
AT DECEMBER 31,
-----------------------------------------------------------------------------
1998 1997 1996 1995 (2) 1994
------------ ------------- ------------- ------------- -------------
BALANCE SHEET DATA: (amounts in thousands)
<S> <C> <C> <C> <C> <C>
Working capital (deficit) $ 55,864 $ 165,945 $ 98,417 $ (2,888) $ 21,785
Total assets 338,621 584,277 435,745 214,750 162,561
Long-term obligation, net of current portion 288,212 280,016 175,028 49,486 31,911
Stockholders' equity (1) 12,989 197,732 174,899 103,681 88,259
</TABLE>
[FN]
(1) No cash dividends were paid during any period presented.
(2) The financial information related to Russia and included in the 1995
presentation contains information at, and for the nine months ended,
September 30, 1995, the end of the fiscal period for GEOILBENT.
</FN>
<PAGE> 26
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
PRINCIPLES OF CONSOLIDATION AND ACCOUNTING METHODS
The Company includes the results of operations of Benton-Vinccler in its
consolidated financial statements and reflects the 20% ownership interest of
Vinccler as a minority interest. Beginning in 1995, GEOILBENT has been included
in the consolidated financial statements based on a fiscal period ending
September 30. Results of operations for GEOILBENT reflect the twelve months
ended September 30, 1996, 1997 and 1998. The Company's investment in GEOILBENT
is proportionately consolidated based on the Company's ownership interest, and
for oil and gas reserve information, the Company reports its 34% share of the
reserves attributable to GEOILBENT. The Company uses the equity method of
accounting for its investments in Severneftegaz.
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all acquisition, exploration,
and development costs incurred. The Company accounts for its oil and gas
properties using cost centers on a country by country basis. Proceeds from sales
of oil and gas properties are credited to the full-cost pools. Capitalized costs
of oil and gas properties are amortized within the cost centers on an overall
unit-of-production method using proved oil and gas reserves as audited by
independent petroleum engineers. Costs amortized include all capitalized costs
(less accumulated amortization and impairment), the estimated future
expenditures (based on current costs) to be incurred in developing proved
reserves, and estimated dismantlement, restoration and abandonment costs (see
Note 1 of Notes to the Consolidated Financial Statements).
Statement of Financial Accounting Standards No. 133 ("SFAS 133") establishes
accounting and reporting standards for derivative instruments and hedging
activities. This statement is effective for all fiscal quarters of all fiscal
years beginning after June 15, 1999. The Company does not use derivative or
hedging instruments. As a result, the Company does not believe the adoption of
the standard will have a material effect on its results of operations or
financial position.
The following discussion of the results of operations and financial condition as
of December 31, 1998 and 1997 and for each of the years in the three year period
ended December 31, 1998, respectively, should be read in conjunction with the
Company's Consolidated Financial Statements and related Notes thereto.
RESULTS OF OPERATIONS
The Company's results of operations for the year ended December 31, 1998,
reflected the results for Benton-Vinccler, C.A. in Venezuela, which accounted
for more than 90% of the Company's production and oil sales revenue. As a result
of declines in world crude oil prices and lower production from the South
Monagas Unit due to operational problems with certain high volume wells, oil
sales in Venezuela were 45% lower in 1998 compared to 1997 with a 33% decrease
in realized fees per barrel (from $10.01 in 1997 to $6.75 in 1998) and a 21%
decrease in oil sales quantities (from 15,394,807 Bbls of oil in 1997 to
12,172,352 Bbls of oil in 1998). Additionally, the Company recognized full cost
ceiling limitation write-downs of its oil and gas properties in Venezuela and
Russia of $187.8 million and $10.1 million, respectively, and a $6.1 million
impairment of capitalized costs associated with certain exploration activities.
The Company also experienced increased interest expense as a result of the
issuance of $115.0 million of senior unsecured notes in the fourth quarter of
1997. Benton-Vinccler also experienced increased operating expenses primarily in
the areas of workovers, transportation and chemical costs, and increased capital
requirements for production facilities. The increased costs resulted in
increased per barrel lease operating costs and, especially when combined with
the decreased fee realizations, represented a significantly higher percentage of
oil sales revenues during the period than in the prior period.
The following table presents selected expense items as a percentage of oil and
gas sales:
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------ -------------
<S> <C> <C> <C>
Lease Operating Costs and Production Taxes 49.5% 25.5% 16.6%
Depletion, Depreciation and Amortization 39.5 29.0 23.4
General and Administrative 28.4 14.3 12.8
Interest 36.5 14.8 10.9
</TABLE>
<PAGE> 27
27
YEARS ENDED DECEMBER 31, 1998 AND 1997
The Company had revenues of $112.1 million for the year ended December 31, 1998.
Expenses incurred during the period consisted of lease operating costs and
production taxes of $44.7 million, depletion, depreciation and amortization
expense of $35.6 million, write-down and impairment of oil and gas properties of
$204.0 million, general and administrative expense of $25.6 million, interest
expense of $32.9 million, income tax benefit of $24.2 million and minority
interest reduction of $22.9 million. Net loss for the period was $183.6 million
or $6.21 per share (diluted).
By comparison, the Company had revenues of $179.0 million for the year ended
December 31, 1997. Expenses incurred during the period consisted of lease
operating costs and production taxes of $41.9 million, depletion, depreciation
and amortization expense of $47.6 million, general and administrative expense of
$23.4 million, interest expense of $24.2 million, income tax expense of $17.5
million, minority interest of $6.3 million. Net income for the period was $18.0
million or $0.59 per share (diluted).
Revenues decreased $66.9 million, or 37%, during the year ended December 31,
1998 compared to the corresponding period of 1997 primarily due to decreased oil
sales revenue in Venezuela as a result of declines in world crude oil prices and
a 21% decrease in oil sales quantities due largely to operational problems with
certain high volume wells. Sales quantities for the year ended December 31, 1998
from Venezuela and Russia were 12,172,352 Bbls and 923,602 Bbls, respectively,
compared to 15,394,807 Bbls and 880,148 Bbls, respectively, for the year ended
December 31, 1997. Prices for crude oil per Bbl averaged $6.75 (pursuant to
terms of an operating service agreement) from Venezuela and $8.72 from Russia
for the year ended December 31, 1998 compared to $10.01 and $11.28,
respectively, for the year ended December 31, 1997. Foreign exchange gains were
$5.5 million higher in 1998 compared to 1997 primarily due to the significant
devaluation of the Russian Ruble during August and September of 1998.
Lease operating costs and production taxes increased $2.8 million, or 7%, during
the year ended December 31, 1998 compared to 1997 primarily due to continuing
maturation of the Uracoa oil field in Venezuela resulting in higher water
handling, gas handling, workover, transportation and chemical costs. The
increase was partially offset by the devaluation of the Russian ruble, Russian
legislation reducing penalties on late tax payments and reduced oil production
in Venezuela. Depletion, depreciation and amortization decreased $12.0 million,
or 25%, during the year ended December 31, 1998 compared to the corresponding
period of 1997 primarily due to write-downs of oil and gas properties in
Venezuela and Russia and reduced oil sales in Venezuela in 1998, partially
offset by increased capital requirements in Venezuela. Depletion expense per BOE
produced from Venezuela and Russia during the year ended December 31, 1998 was
$2.62 and $2.68, respectively, compared to $2.83 and $3.50, respectively, during
the previous year. Additionally, the Company recognized write-downs of oil and
gas properties during 1998 in the Venezuela and Russia cost centers of $187.8
million and $10.1 million, respectively, pursuant to the ceiling limitation
prescribed by the full cost method of accounting. The write-downs were a result
of the effect of declines in world crude oil prices on the prices realized by
the Company for its Venezuelan and Russian oil sales. The Company also
recognized $6.1 million of impairment expense associated with certain
exploration activities. General and administrative expenses increased $2.2
million, or 9%, during the year ended December 31, 1998 compared to 1997
primarily due to an allowance for doubtful accounts related to amounts owed to
the Company by its Chief Executive Officer (see Note 15 of Notes to the
Consolidated Financial Statements) and costs incurred in the Company's China
operation partially offset by decreased Venezuelan municipal taxes (which are a
function of oil revenues). Interest expense increased $8.7 million, or 36%, in
1998 compared to 1997 primarily due to the issuance of $115 million in senior
unsecured notes in November 1997. Income tax expense decreased $41.7 million, or
238%, during the year ended December 31, 1998 compared to 1997 primarily due to
decreased taxable income in Venezuela as a result of write-downs of oil and gas
properties. The net income attributable to the minority interest decreased $29.2
million, or 463%, for 1998 compared to 1997 as a result of the decreased
profitability of Benton-Vinccler's operations in Venezuela.
YEARS ENDED DECEMBER 31, 1997 AND 1996
The Company had revenues of $179.0 million for the year ended December 31, 1997.
Expenses incurred during the period consisted of lease operating costs and
production taxes of $41.9 million, depletion, depreciation and amortization
expense of $47.6 million, general and administrative expense of $23.4 million,
interest expense of $24.2 million, income tax expense of $17.5 million and
minority interest of $6.3 million. Net income for the period was $18.0 million
or $0.59 per share (diluted).
By comparison, the Company had revenues of $165.1 million for the year ended
December 31, 1996. Expenses incurred during the period consisted of lease
operating costs and production taxes of $24.5 million, depletion, depreciation
and amortization expense of $34.5 million, general and administrative expense of
$18.9 million, interest expense of $16.1 million, partnership exchange expense
of $2.1 million, income tax expense of $20.5 million, minority interest of $10.0
<PAGE> 28
28
million and an extraordinary charge for early retirement of debt, net of tax
benefit, of $10.1 million. Net income for the period was $28.3 million or $0.95
per share (diluted).
Revenues increased $13.9 million, or 8%, during the year ended December 31, 1997
compared to the corresponding period of 1996 primarily due to increased oil
sales in Venezuela and increased investment earnings partially offset by the
gain on sale of properties in 1996. Sales quantities for the year ended December
31, 1997 from Venezuela and Russia were 15,394,807 Bbls and 880,148 Bbls,
respectively, compared to 12,647,987 Bbls and 765,137 Bbls, respectively, for
the year ended December 31, 1996. Prices for crude oil per Bbl averaged $10.01
(pursuant to terms of an operating service agreement) from Venezuela and $11.28
from Russia for the year ended December 31, 1997 compared to $10.82 and $11.82,
respectively, for the year ended December 31, 1996. Revenues for 1997 were
increased by a foreign exchange gain of $2.3 million compared to a gain of $2.8
million in 1996.
Lease operating costs and production taxes increased $17.4 million, or 71%,
during the year ended December 31, 1997 compared to 1996 primarily due to
continued growth of the Company's Venezuelan operations, as well as the
continuing maturation of the Uracoa oil field resulting in higher water
handling, gas handling, workover, transportation and chemical costs. Depletion,
depreciation and amortization increased $13.1 million, or 38%, during the year
ended December 31, 1997 compared to the corresponding period in 1996. Depletion
expense per BOE produced from Venezuela and Russia during the year ended
December 31, 1997 was $2.83 and $3.50, respectively, compared to $2.33 and
$3.59, respectively, during the previous year. General and administrative
expenses increased $4.5 million, or 24% during the year ended December 31, 1997
compared to 1996 primarily due to the Company's increased corporate activity
associated with the growth of the Company's business and increased Venezuelan
municipal taxes (which are a function of growing oil revenues and increased tax
rates). Interest expense increased $8.1 million, or 50%, in 1997 compared to
1996 primarily due to the issuance of $125 million in senior unsecured notes in
May 1996 and to the issuance of $115 million in senior unsecured notes in
November 1997. Income tax expense decreased $3.0 million, or 15%, during the
year ended December 31, 1997 compared to 1996 primarily due to decreased taxable
income in Venezuela. The net income attributable to the minority interest
decreased $3.7 million, or 37%, for 1997 compared to 1996 as a result of the
decreased profitability of Benton-Vinccler's operations in Venezuela.
DOMESTIC OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy Company, LLC
("Molino Energy"), which held 100% of these leases. The project area covers the
Molino, Gaviota and Caliente Fields, located approximately 35 miles west of
Santa Barbara, California. In consideration of the 40% participation interest in
the leases, the Company became the operator of the project and paid 100% of the
first $3.7 million and 53% of the remainder of the costs of the first well
drilled on the block. During 1998, the 2199 #7 exploratory well was drilled to
the Gaviota anticline. Drill stem tests proved to be inconclusive or
non-commercial, and the well was temporarily abandoned for further evaluation.
The Company's share of the drilling and testing of the 2199 #7 well was $8.5
million. In November 1998, the Company entered into an agreement to acquire
Molino Energy's interest in the leases in exchange for the release of its joint
interest billing obligations of approximately $1.9 million. The agreement to
acquire Molino Energy's interest will be finalized upon the completion of
certain lot splits and the assignment of various permits and rights.
INTERNATIONAL OPERATIONS
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%. However, Benton-Vinccler reported significantly lower effective tax
rates for 1996 and 1998 due to the effect of the devaluation of the Bolivar
while Benton-Vinccler uses the U.S dollar as its functional currency, and
further in 1998 due to a deferred tax asset valuation allowance. The Company
cannot predict the timing or impact of future devaluations in Venezuela.
A 3-D seismic survey has been conducted over the southwestern portion of the
Delta Centro Block in Venezuela at an expected total cost to the Company of $8.3
million, of which $6.8 million had been spent though December 31, 1998. During
the first quarter of 1999, drilling commenced on the Jarina-1 X, the first of
the block's exploration wells, with a total anticipated cost to the Company of
approximately $5.6 million. Subsequent seismic and drilling programs will be
based on the results of the Jarina-1 X well. The Company's operations related to
Delta Centro will be subject to oil and gas industry taxation, which currently
provides for royalties of 16.66% and income taxes of 67.7%.
GEOILBENT is subject to a statutory income tax rate of 35%. GEOILBENT has also
been subject to various other tax burdens, including an oil export tariff which
was terminated effective July 1, 1996. Excise, pipeline and other taxes
(including a new oil export tariff introduced in 1999) continue to be levied on
all oil producers and certain exporters. The Russian regulatory environment
continues to be volatile and the Company is unable to predict the impact of
taxes, duties and other burdens for the future.
<PAGE> 29
29
In December 1996, the Company acquired Benton Offshore China Company, a
privately held company headquartered in Denver, Colorado. Benton Offshore China
Company's principal asset is a petroleum contract with CNOOC for an area known
as Wan'An Bei, WAB-21. The WAB-21 petroleum contract covers 6.2 million acres in
the South China Sea, with an option for another one million acres under certain
circumstances, and lies within an area which is the subject of a territorial
dispute between the People's Republic of China and Vietnam. Vietnam has also
executed an agreement on a portion of the same offshore acreage with Conoco Inc.
The territorial dispute has existed for many years, and there has been limited
exploration and no development activity in the area under dispute. It is
uncertain when or how this dispute will be resolved, and under what terms the
various countries and parties to the agreements may participate in the
resolution, although certain proposed economic solutions currently under
discussion would result in the Company's interest being reduced. Benton Offshore
China Company has submitted plans and budgets to CNOOC for an initial seismic
program to survey the area. However, exploration activities will be subject to
resolution of such territorial dispute. At December 31, 1998, the Company has
recorded no proved reserves attributable to this petroleum contract.
In August 1997, the Company acquired the rights to a PSA with Jordan's NRA to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which is expected to last
approximately two years. If the Company ultimately elects to continue through
phases two and three, it would be obligated to spend an additional $18 million
over the succeeding six years.
In October 1997, the Company signed a farmout agreement with Shell whereby the
Company will acquire a 50% participation interest in Shell's Liaohe area onshore
exploration project in northeast China. Shell holds a petroleum contract with
China National Petroleum Corporation to explore and develop the deep rights in
the Qingshui Block, a 563 square kilometer area (approximately 140,000 acres) in
the delta of the Liaohe River. Shell will be the operator of the project. In
July 1998, the Company paid to Shell 50% of Shell's prior investment in the
Block, which was approximately $4 million ($2 million to the Company). The
Company is required to pay 100% of the first $8 million of the costs for the
phase one exploration period, after which any development costs will be shared
equally. If a commercial well results from phase one and the Company elects to
continue to phase two, then the Company will pay 100% of the first $8 million of
the costs of the second phase of the exploration period, after which any
development costs will be shared equally. If a commercial well does not result
from phase one and the Company elects to continue to phase two, then the Company
and Shell will share costs equally. The Company and Shell will share costs
equally for the third exploration phase, if any. During the first quarter of
1999, drilling commenced on the Qing-22 Deep well as a part of the phase one
exploration period activities.
In December 1997, the Company signed a memorandum of understanding with Petrosen
to receive a minimum 45% working interest in and to operate the approximately
one-million acre onshore Thies Block in western Senegal. In addition, the
Company obtained exclusive rights from Petrosen to evaluate and reprocess
geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea Bissau border in the south. The Company may
also choose certain blocks for further data acquisition and exploration
drilling. The Company's working interest in any offshore discovery will be 85%
with the remainder held by Petrosen. The Company's $5.4 million work commitment
on the Thies Block, where Petrosen has recently drilled and completed the
Gadiaga #2 discovery well, consists of hooking up the existing well, drilling
two additional wells and constructing a 41-kilometer (approximately 25-mile) gas
pipeline to Senegal's main electric generating facility near Dakar. The
Company's minimum commitment related to the offshore blocks involves seismic
reprocessing to be followed by additional data acquisition and drilling at the
Company's discretion.
In April 1998, the Company signed an agreement to earn a 40% equity interest in
Severneftegaz. Severneftegaz owns the exclusive rights to evaluate, develop and
produce the natural gas, condensate, and oil reserves in the Samburg and
Yevo-Yakha License Blocks in West Siberia. The two blocks comprise 837,000 acres
within and adjacent to the Urengoy field, Russia's largest producing natural gas
field. Pursuant to a Cooperation Agreement between the Company and
Severneftegaz, the Company will earn a 40% equity interest in exchange for
providing the initial capital needed to achieve natural gas production. The
Company's capital commitment will be in the form of a $100 million credit
facility for the project, the terms of which have yet to be finalized, which is
expected to be disbursed over the initial two-year development phase. The
Company received voting shares representing a 40% ownership in Severneftegaz
that contain restrictions on their sale and transfer. The Share Disposition
Agreement provides for removal of the restrictions as disbursements are made
under the credit facility. Due to the significant influence it exercises over
the operating and financial policies of Severneftegaz, the Company has accounted
for its interest in Severneftegaz using the equity method. Certain provisions of
Russian corporate law would effectively require minority shareholder consent in
the making of new agreements between the Company and Severneftegaz, or to the
changing of any terms in any existing agreements, including the conditions upon
which the restrictions on the shares could be removed, between the two such as
the Cooperation Agreement and the Share Disposition Agreement.
<PAGE> 30
30
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION
The Company's results of operations and cash flow are affected by changing oil
and gas prices. However, the Company's Venezuelan revenues are based on a fee
adjusted quarterly by the percentage change of a basket of crude oil prices
instead of by absolute dollar changes, which dampens both any upward and
downward effects of changing prices on the Company's Venezuelan revenues and
cash flows. If the price of oil and gas increases, there could be an increase in
the cost to the Company for drilling and related services because of increased
demand, as well as an increase in revenues. Fluctuations in oil and gas prices
may affect the Company's total planned development activities and capital
expenditure program.
There are presently no restrictions in either Venezuela or Russia that restrict
converting U.S. dollars into local currency. However, from June 1994 through
April 1996, Venezuela implemented exchange controls which significantly limited
the ability to convert local currency into U.S. dollars. Because payments made
to Benton-Vinccler are made in U.S. dollars into its United States bank account,
and Benton-Vinccler is not subject to regulations requiring the conversion or
repatriation of those dollars back into Venezuela, the exchange controls did not
have a material adverse effect on Benton-Vinccler or the Company. Currently,
there are no exchange controls in Venezuela or Russia that restrict conversion
of local currency into U.S. dollars.
Within the United States, inflation has had a minimal effect on the Company, but
it is potentially an important factor in results of operations in Venezuela and
Russia. With respect to Benton-Vinccler and GEOILBENT, substantially all of the
sources of funds, including the proceeds from oil sales, the Company's
contributions and credit financings, are denominated in U.S. dollars, while
local transactions in Russia and Venezuela are conducted in local currency. If
the rate of increase in the value of the dollar compared to the bolivar
continues to be less than the rate of inflation in Venezuela, then inflation
could be expected to have an adverse effect on Benton-Vinccler.
During the year ended December 31, 1998, the Company realized net foreign
exchange gains, primarily as a result of the decline in the value of the
Venezuelan bolivar and the Russian ruble during periods when the Company's
Venezuela-related subsidiaries and GEOILBENT had substantial net monetary
liabilities denominated in bolivares and rubles. During the year ended December
31, 1998, the Company's net foreign exchange gains attributable to its
Venezuelan and Russian operations were $1.7 million and $6.0 million,
respectively. However, there are many factors affecting foreign exchange rates
and resulting exchange gains and losses, many of which are beyond the control of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the U.S. dollar. It is not possible to predict the extent
to which the Company may be affected by future changes in exchange rates and
exchange controls.
The Company's operations are affected by political developments and laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and results.
CAPITAL RESOURCES AND LIQUIDITY
The oil and gas industry is a highly capital intensive business. The Company
requires capital principally to fund the following costs: (i) drilling and
completion costs of wells and the cost of production and transportation
facilities; (ii) geological, geophysical and seismic costs; and (iii)
acquisition of interests in oil and gas properties. The amount of available
capital will affect the scope of the Company's operations and the rate of its
growth.
The net funds raised and/or used in each of the operating, investing and
financing activities for each of the years ended December 31, are summarized in
the following table and discussed in further detail below:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------
(IN THOUSANDS)
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Net cash provided by operating activities $ 8,561 $ 93,948 $ 84,852
Net cash used in investing activities (8,017) (216,028) (164,772)
Net cash provided by financing activities 5,663 101,588 106,172
------- --------- --------
Net increase (decrease) in cash $ 6,207 $ (20,492) $ 26,252
======= ========= ========
</TABLE>
At December 31, 1998, the Company had current assets of $92.8 million and
current liabilities of $36.9 million, resulting in working capital of $55.9
million and current ratio of 2.51:1. This compares to the Company's working
capital of
<PAGE> 31
31
$165.9 million and a current ratio of 3.84:1 at December 31, 1997. The decrease
of $110.0 million was due to expenditures related to the continuing development
of the South Monagas Unit in Venezuela and reduced South Monagas oil sales
revenues resulting from declines in world crude oil prices and reduced sales
quantities.
CASH FLOW FROM OPERATING ACTIVITIES. During 1998, 1997 and 1996, net cash
provided by operating activities was approximately $8.6 million, $93.9 million
and $84.9 million, respectively. Cash flow from operating activities decreased
by $85.3 million in 1998 primarily due to decreased oil sales from Venezuela as
a result of declines in world crude oil prices and reduced sales quantities.
Cash flow from operating activities increased $9.0 million in 1997 primarily due
to increased oil production in Venezuela.
CASH FLOW FROM INVESTING ACTIVITIES. During 1998, 1997 and 1996, the Company had
drilling and production related capital expenditures of approximately $120.0
million, $109.8 million and $95.5 million, respectively. Of the 1998
expenditures, $80.2 million was attributable to the development of the South
Monagas Unit in Venezuela, $14.4 million related to the development of the North
Gubkinskoye Field in Russia, $5.7 million related to the development of the
Gaviota lease in Santa Barbara County, California, $4.2 million related to a 3-D
seismic survey in the Delta Centro Block in Venezuela, $4.0 million related to
the development of the Qingshui Block in China, $3.6 million related to the
Samburg Block in Russia (in addition to $8.3 million loaned to Severneftegaz),
$2.3 million related to the development of the Sirhan Block in Jordan and $5.6
million was attributable to other projects. In 1996, the Company also sold
certain oil and gas properties for net proceeds of approximately $34.6 million.
During 1998, the Company instituted a capital expenditure program which
minimized expenditures to those that the Company believed were necessary in
order to maintain current producing properties. This policy was instituted in
response to the low market price for oil. The Company expects to continue
limiting capital expenditures at this maintenance level until such time as world
oil prices increase or sufficient funding from outside sources is available.
The Company expects 1999 capital expenditures of approximately $45.0 million,
including $7.1 million in expenditures by GEOILBENT in Russia, net to the
Company's interest (which will be funded from borrowings under the EBRD Credit
Facility, cash flow from operations or other financings). Additionally, the
Company anticipates providing or arranging loans of up to $100 million over the
next two years to Severneftegaz pursuant to an equity acquisition agreement
signed in April 1998. The Company is currently evaluating funding alternatives
for the loans to Severneftegaz. The Company's indentures contain provisions that
restrict the manner in which the Company can invest in certain of its current
operations including GEOILBENT.
The Company continually assesses its 1999 capital expenditure program in view of
its financial resources and of industry and commodity price changes. Its total
1999 capital expenditure requirements include approximately $10-15 million at
South Monagas Unit, $10-12 million for well commitments in China and at Delta
Centro, and $7-10 million for Severneftegaz. The Company anticipates that
Geoilbent will continue to fund itself through its own cash flows and credit
facilities. The Company's remaining capital commitments worldwide are relatively
minimal and for the most part are substantially at the Company's discretion. The
timing and size of the 1999 investments for Severneftegaz are also substantially
under the Company's discretion. The Company believes it has or can obtain
sufficient funding for certain of its expected capital requirements from working
capital and cash flow from operations.
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond the Company's control.
If oil prices continue at current levels or decline moderately, and if oil
production continues at expected levels, the Company believes that its current
cash and cash provided by operating activities will be sufficient to meet the
Company's liquidity needs for routine operations and to service its outstanding
debt through 1999. The Company continues to evaluate and review strategic
alternatives and has engaged J.P. Morgan Securities, Inc. to advise the Company
related to these alternatives. In the event that future cash requirements are
greater than the Company's financial resources, the Company intends to pursue
strategic joint ventures or alliances with other industry partners, sell
property interests, merge or combine with another entity, or issue debt or
equity securities.
CASH FLOW FROM FINANCING ACTIVITIES. In May 1996, the Company issued $125
million in 11.625% senior unsecured notes due May 1, 2003. In November 1997, the
Company issued $115 million in 9.375% senior unsecured notes due November 1,
2007, of which the Company subsequently repurchased $10 million at their par
value. Interest on the notes is due May 1st and November 1st of each year. The
indenture agreements provide for certain limitations on liens, additional
indebtedness, certain investment and capital expenditures, dividends, mergers
and sales of assets. At December 31, 1998, the Company was in compliance with
all covenants of the indentures.
<PAGE> 32
32
The EBRD and IMB have agreed to lend a total of $65 million to GEOILBENT (owned
34% by the Company) under parallel reserve-based loan agreements. As of December
31, 1998, GEOILBENT had borrowed $19 million and in March 1999, GEOILBENT
borrowed an additional $8.3 million under these agreements. The proceeds from
the loans are being used by GEOILBENT to develop the North Gubkinskoye Field in
West Siberia, Russia. Additional borrowings will be based on achieving certain
reserve and production milestones.
YEAR 2000 COMPLIANCE
The Year 2000 problem concerns the inability of information systems to properly
recognize and process date-sensitive information beyond January 1, 2000. The
Company began a process of assessing its information technology systems in
November 1997 and has to date not uncovered any significant Year 2000
deficiencies. Substantially all of the software utilized by the Company is
purchased or licensed from external providers. The Company's home office
business systems are Year 2000 compliant. Its subsidiaries are currently in the
process of upgrading their business systems, with completion anticipated during
the second quarter of 1999 in Venezuela and the third quarter of 1999 in Russia.
A review of the Company's non-financial software and imbedded chip technology is
currently underway to assess the impact of the Year 2000 on systems such as
plant flow control devices, product measurement and delivery devices and fire or
other disaster-related safety systems. To date, the costs associated with
required modifications to become Year 2000 compliant have not exceeded $100,000,
and the Company does not anticipate that the cost of converting any
non-compliant systems will be material to its financial condition.
The Company anticipates the completion of the process of obtaining Year 2000
compliance information from its material suppliers and customers by April 30,
1999. To the extent that the Company does not receive adequate responses from
its material third-party suppliers and customers by April 30, 1999, it is
prepared to develop contingency plans that would include changing suppliers and
customers to those who have demonstrated Year 2000 readiness. However, there can
be no assurance that the Company will be successful in finding such alternative
suppliers and customers. The oil produced in Venezuela by the Company, which is
delivered to PDVSA under the terms of an operating service agreement lasting
until 2012, represented approximately 91% of the Company's oil sales during
1998. In the event that PDVSA is unable to accept deliveries of, or make payment
for, the oil produced by the Company due to a Year 2000 failure, the Company's
operations and financial position could be materially and adversely affected.
The failure to correct a material Year 2000 problem could result in an
interruption in, or a failure of, certain normal business activities or
operations. Such failures could materially and adversely affect the Company's
results of operations, liquidity and financial condition. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from the
uncertainty of the Year 2000 readiness of third-party suppliers and customers,
the Company is unable to determine at this time whether the consequences of Year
2000 failures will have a material impact on the Company's results of
operations, liquidity or financial condition.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from adverse changes in oil and gas
prices, interest rates and foreign exchange, as discussed below.
OIL AND GAS PRICES
As an independent oil and gas producer, the Company's revenue and profitability,
reserve values, access to capital and future rate of growth are substantially
dependent upon the prevailing prices of crude oil and condensate. The Company
currently neither produces nor records reserves related to natural gas.
Prevailing prices for such commodities are subject to wide fluctuation in
response to relatively minor changes in supply and demand and a variety of
additional factors beyond the control of the Company. Historically, prices
received for oil and gas production have been volatile and unpredictable, and
such volatility is expected to continue. Average realizations per barrel have
declined from $10.07 in 1997 to $6.89 in 1998. From time to time, the Company
has utilized hedging transactions with respect to a portion of its oil and gas
production to achieve a more predictable cash flow, as well as to reduce its
exposure to price fluctuations, but the Company has utilized no such
transactions since 1996, and does not expect to utilize such transactions in the
near future. While hedging limits the downside risk of adverse price movements,
it may also limit future revenues from favorable price movements. Because gains
or losses associated with hedging transactions are included in oil and gas
revenues when the hedged production is delivered, such gains and losses are
generally offset by similar changes in the realized prices of the commodities.
The Company did not enter into any commodity hedging agreements during 1997 and
1998.
<PAGE> 33
33
INTEREST RATES
Total long term debt of $288.2 million at December 31, 1998, included $230
million of fixed-rate senior unsecured notes maturing in 2003 ($125 million) and
2007 ($105 million). Another $51.6 million of debt is attributable to
floating-rate back-to-back loan facilities wherein Benton-Vinccler and GEOILBENT
pay floating-rate interest to a bank, which then pays to the Company interest on
cash collateral deposited by the Company to support the loans, such interest to
the Company being equal to the floating rate payment less 0.375% for Benton-
Vinccler and less 0.25% for GEOILBENT, thereby mitigating the floating-rate
interest rate risk of such debt. The balance of $6.4 million (2% of total long
term debt), consisting primarily of the Company's share of debt owed by
Geoilbent, is subject to the market volatility of floating rates. A hypothetical
10% adverse change in the floating rate would not have had a material affect on
the Company's results of operations for the fiscal year ended December 31, 1998.
FOREIGN EXCHANGE
The Company's operations are located primarily outside of the United States. In
particular, the Company's current oil producing operations are located in
Venezuela and Russia, countries which have had recent histories of significant
inflation and devaluation. For the Venezuelan operations, revenues are received
under a contract in effect through 2012 in US dollars; expenditures are both in
US dollars and local currency. For the Russian operations, revenues are received
primarily in US dollars, with less than 15% of such revenues being received in
local currency; expenditures are both in US dollars and local currency, although
a larger percentage of the expenditures were in local currency. The Company has
utilized no currency hedging programs to mitigate any risks associated with
operations in these countries, and therefore the Company's financial results are
subject to favorable or unfavorable fluctuations in exchange rates and inflation
in these countries.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The information required by this item is included herein on pages S-1 through
S-29.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported under this item.
<PAGE> 34
34
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
*
ITEM 11. EXECUTIVE COMPENSATION
*
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
*
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
*
[FN]
* Reference is made to information under the captions "Election of
Directors", "Executive Officers", "Executive Compensation", "Security
Ownership of Certain Beneficial Owners and Management", and "Certain
Relationships and Related Transactions" in the Company's Proxy Statement
for the 1999 Annual Meeting of Stockholders.
</FN>
<PAGE> 35
35
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Index to Financial Statements:
<TABLE>
<CAPTION>
Page
----
<S> <C>
Reports of Independent Accountants ......................................................S-1
Consolidated Balance Sheets at December 31, 1998 and 1997 ...............................S-3
Consolidated Statements of Operations for the Years Ended
December 31, 1998, 1997 and 1996 ........................................................S-4
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1998, 1997 and 1996 ............................................S-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996 ........................................................S-6
Notes to Consolidated Financial Statements...............................................S-8
</TABLE>
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:
<TABLE>
<S> <C>
3.1. Certificate of Incorporation of the Company filed September 9,
1988 (Incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement (Registration No. 33-26333).
3.2 Amendment to Certificate of Incorporation of the Company filed
June 7, 1991 (Previously filed as an exhibit to the Company's
S-1 Registration Statement (Registration No. 33-39214)).
3.3 Restated Bylaws of the Company (Incorporated by reference to
Exhibit 3.3 to the Company's Form 10-K for the year ended
December 31, 1996).
4.1 Form of Common Stock Certificate (Previously filed as an exhibit
to the Company's S-1 Registration Statement (Registration No.
33-26333)).
10.4 Form of Employment Agreements (Exhibit 10.19) (Previously filed
as an exhibit to the Company's S-1 Registration Statement
(Registration No. 33-26333)).
10.7 Benton Oil and Gas Company 1991-1992 Stock Option Plan (Exhibit
10.14) (Previously filed as an exhibit to the Company's S-1
Registration Statement (Registration No. 33-43662)).
10.8 Benton Oil and Gas Company Directors' Stock Option Plan (Exhibit
10.15) (Previously filed as an exhibit to the Company's S-1
Registration Statement (Registration No. 33-43662)).
10.9 Agreement dated October 16, 1991 among Benton Oil and Gas
Company, Puror State Geological Enterprises for Survey,
Exploration, Production and Refining of Oil and Gas; and Puror
Oil and Gas Production Association (Exhibit 10.14) (Previously
filed as an exhibit to the Company's S-1 Registration Statement
(Registration No. 33-46077)).
</TABLE>
<PAGE> 36
36
<TABLE>
<S> <C>
10.10 Operating Service Agreement between the Company and Lagoven,
S.A., which has been subsequently combined into PDVSA Petroleo y
Gas, S.A., dated July 31, 1992, (portions have been omitted
pursuant to Rule 406 promulgated under the Securities Act of
1933 and filed separately with the Securities and Exchange
Commission--Exhibit 10.25) (Previously filed as an exhibit to
the Company's S-1 Registration Statement (Registration No.
33-52436)).
10.16 Indenture dated May 2, 1996 between Benton Oil and Gas Company
and First Trust of New York, National Association, Trustee
related to $125,000,000, 11 5/8% Senior Notes Due 2003
(Incorporated by reference to Exhibit 4.1 to the Company's S-4
Registration Statement filed June 17, 1996, SEC Registration No.
333-06125).
10.17 Indenture dated November 1, 1997 between Benton Oil and Gas
Company and First Trust of New York, National Association,
Trustee related to an aggregate of $115,000,000 principal amount
of 9 3/8% Senior Notes due 2007 (Incorporated by reference to
Exhibit 10.1 to the Company's Form 10-Q for the quarter ended
September 30, 1997).
21.1 List of subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Deloitte & Touche LLP.
23.3 Consent of Huddleston & Co., Inc.
27.1 Financial Data Schedule.
</TABLE>
[FN]
(b) Reports on Form 8-K
No Form 8-K was filed during the last quarter of the registrant's fiscal
year.
</FN>
<PAGE> 37
37
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Stockholders of Benton Oil and Gas Company
In our opinion, the accompanying consolidated balance sheet as of December 31,
1998 and the related consolidated statements of operations, stockholders' equity
and cash flows present fairly, in all material respects, the financial position
of Benton Oil and Gas Company and its subsidiaries (the "Company") at December
31, 1998, and the results of their operations and their cash flows for the year
then ended, in conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
San Francisco, California
March 25, 1999
S-1
<PAGE> 38
38
INDEPENDENT AUDITORS' REPORT
- ----------------------------
Board of Directors and Stockholders
Benton Oil and Gas Company
Carpinteria, California
We have audited the accompanying consolidated balance sheet of Benton Oil and
Gas Company and subsidiaries as of December 31, 1997, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
each of the two years in the period ended December 31, 1997. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Benton Oil and Gas Company and
subsidiaries at December 31, 1997 and the results of their operations and their
cash flows for each of the two years in the period ended December 31, 1997 in
conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Los Angeles, California
March 24, 1998
S-2
<PAGE> 39
39
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1998 1997
------------- -------------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents $ 18,147 $ 11,940
Restricted cash 12 48
Marketable securities 41,173 156,436
Accounts and notes receivable:
Accrued oil and gas revenue 17,307 45,379
Joint interest and other, net 12,482 8,029
Prepaid expenses and other 3,688 2,463
-------- -------
TOTAL CURRENT ASSETS 92,809 224,295
RESTRICTED CASH 65,670 74,288
OTHER ASSETS 11,725 12,497
DEFERRED INCOME TAXES 2,976 -
INVESTMENT IN AND ADVANCES TO AFFILIATED COMPANY 11,975 -
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of
$35,228 and $31,588 excluded from
amortization in 1998 and 1997, respectively) 483,494 367,756
Furniture and fixtures 9,608 5,734
-------- --------
493,102 373,490
Accumulated depletion, impairment and depreciation (339,636) (100,293)
-------- --------
153,466 273,197
-------- --------
$338,621 $584,277
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other $ 10,014 $ 27,567
Accrued interest payable 5,527 5,533
Accrued expenses 19,342 17,722
Income taxes payable 1,847 4,535
Short term borrowings - 1,530
Current portion of long term debt 215 1,463
-------- -------
TOTAL CURRENT LIABILITIES 36,945 58,350
DEFERRED INCOME TAXES - 24,811
LONG TERM DEBT 288,212 280,016
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST 475 23,368
STOCKHOLDERS' EQUITY
Preferred stock, par value $0.01 a share;
Authorized 5,000 shares; outstanding, none
Common stock, par value $0.01 a share;
Authorized 80,000 shares and 40,000 shares at December 31, 1998
and 1997, respectively; issued 29,627 and 29,522 shares
at December 31, 1998 and 1997, respectively 296 295
Additional paid-in capital 147,054 146,125
Retained earnings (deficit) (131,569) 52,011
Treasury stock, at cost, 50 shares (699) (699)
Employee note receivable, net (2,093) -
------- ------
TOTAL STOCKHOLDERS' EQUITY 12,989 197,732
-------- -------
$338,621 $584,277
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
S-3
<PAGE> 40
40
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
REVENUES
Oil and gas sales $ 90,271 $ 163,957 $ 147,703
Gain on sale of properties - - 7,175
Net gain on exchange rates 7,757 2,285 2,820
Investment earnings and other 14,120 12,777 7,368
--------- --------- ---------
112,148 179,019 165,066
--------- --------- ---------
EXPENSES
Lease operating costs and production taxes 44,675 41,887 24,518
Depletion, depreciation and amortization 35,638 47,592 34,525
Write-down and impairment of oil and gas properties 203,993 - -
General and administrative 25,629 23,436 18,906
Interest 32,908 24,245 16,128
Partnership exchange expenses - - 2,140
--------- --------- ---------
342,843 137,160 96,217
--------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST (230,695) 41,859 68,849
INCOME TAX EXPENSE (BENEFIT) (24,220) 17,477 20,508
--------- --------- ---------
INCOME (LOSS) BEFORE MINORITY INTEREST (206,475) 24,382 48,341
MINORITY INTEREST (22,895) 6,333 9,984
--------- --------- ---------
INCOME (LOSS) BEFORE EXTRAORDINARY CHARGE (183,580) 18,049 38,357
EXTRAORDINARY CHARGE FOR EARLY RETIREMENT OF DEBT, NET OF TAX
BENEFIT OF $879 - - 10,075
--------- --------- ---------
NET INCOME (LOSS) $(183,580) $ 18,049 $ 28,282
========= ========= =========
NET INCOME (LOSS) PER COMMON SHARE:
Basic:
Income (loss) before extraordinary charge $ (6.21) $ 0.62 $ 1.42
Extraordinary charge - - 0.38
--------- ------- -------
Net Income (loss) $ (6.21) $ 0.62 $ 1.04
========= ======= =======
Diluted:
Income (loss) before extraordinary charge $ (6.21) $ 0.59 $ 1.29
Extraordinary charge - - 0.34
--------- ------- -------
Net Income (loss) $ (6.21) $ 0.59 $ 0.95
========= ======= =======
</TABLE>
See accompanying notes to consolidated financial statements.
S-4
<PAGE> 41
41
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)
<TABLE>
<CAPTION>
EMPLOYEE
COMMON ADDITIONAL RETAINED NOTE
SHARES COMMON PAID-IN EARNINGS TREASURY RECEIVABLE,
ISSUED STOCK CAPITAL (DEFICIT) STOCK NET TOTAL
------ ----- ------- --------- ----- --- -----
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE AT JANUARY 1, 1996 25,509 $ 255 $ 97,746 $ 5,680 - - $103,681
Issuance of common shares:
Exercise of warrants 994 10 12,134 - - - 12,144
Exercise of stock options 888 9 5,941 - - - 5,950
Conversion of notes and
debentures 711 7 6,870 - - - 6,877
Acquisitions 796 8 18,574 - - - 18,582
Securities registration costs - - (617) - - - (617)
Net income - - - 28,282 - - 28,282
------ ----- --------- --------- ----- ------- -------
BALANCE AT DECEMBER 31, 1996 28,898 289 140,648 33,962 - - 174,899
Issuance of common shares:
Exercise of warrants 343 3 3,524 - - - 3,527
Exercise of stock options 281 3 1,953 - - - 1,956
Treasury stock (50 shares) - - - - $(699) - (699)
Net income - - - 18,049 - - 18,049
------ ----- --------- --------- ----- ------- -------
BALANCE AT DECEMBER 31, 1997 29,522 295 146,125 52,011 (699) - 197,732
Issuance of common shares:
Exercise of stock options 105 1 794 - - - 795
Extension of warrants - - 135 - - - 135
Employee note receivable, net - - - - - $(2,093) (2,093)
Net loss - - - (183,580) - - (183,580)
------ ----- --------- --------- ----- ------- -------
BALANCE AT DECEMBER 31, 1998 29,627 $ 296 $ 147,054 $(131,569) $(699) $(2,093) $12,989
====== ===== ========= ========= ===== ======= =======
</TABLE>
See accompanying notes to consolidated financial statements.
S-5
<PAGE> 42
42
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------
1998 1997 1996
----------- ------------- -------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $(183,580) $ 18,049 $ 28,282
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depletion, depreciation and amortization 35,638 47,592 34,525
Write-down and impairment of oil and gas properties 203,993 - -
Amortization of financing costs 1,442 1,390 670
(Gain) loss on disposition of assets 74 11 (6,950)
Partnership exchange expenses - - 2,140
Allowance for employee notes and accounts receivable 2,900 31 336
Minority interest in undistributed earnings (losses) of subsidiary (22,893) 6,336 9,984
Extraordinary charge for early retirement of debt 10,075
Deferred income taxes (27,787) 8,132 16,679
Changes in operating assets and liabilities:
Accounts and notes receivable 18,626 6,558 (35,516)
Prepaid expenses and other (1,225) (872) (1,377)
Accounts payable (17,553) 5,196 2,022
Accrued interest payable (6) 1,757 2,915
Accrued expenses 1,620 (3,878) 20,342
Income taxes payable (2,688) 3,646 725
-------- -------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 8,561 93,948 84,852
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and equipment - - 34,638
Additions of property and equipment (119,959) (109,760) (95,497)
Investment in and advances to affiliated company (11,975) - -
Increase in restricted cash (230) (13,436) (74,050)
Decrease in restricted cash 8,884 11,600 21,864
Purchases of marketable securities (55,438) (291,943) (133,296)
Maturities of marketable securities 170,701 187,511 81,292
Distributions from limited partnerships - - 277
-------- -------- --------
NET CASH USED IN INVESTING ACTIVITIES (8,017) (216,028) (164,772)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from exercise of stock options and warrants 930 5,483 17,818
Purchase of treasury stock - (699) -
Proceeds from issuance of short term borrowings and notes payable 8,093 116,190 181,921
Payments on short term borrowings and notes payable (2,675) (11,680) (76,469)
Prepayment premiums on debt retirement - - (10,632)
Increase in other assets (685) (7,706) (6,466)
-------- -------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES 5,663 101,588 106,172
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 6,207 (20,492) 26,252
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 11,940 32,432 6,180
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 18,147 $ 11,940 $ 32,432
======== ======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for interest expense $ 31,032 $ 20,860 $ 13,519
======== ======== ========
Cash paid during the year for income taxes $ 3,349 $ 4,589 $ 3,287
======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
S-6
<PAGE> 43
43
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the year ended December 31, 1998, the Company reduced stockholders'
equity by $2.1 million, the portion of the note receivable from its Chief
Executive Officer secured by the Company's stock and stock options. (see Note
15).
During the year ended December 31, 1997, certain trade payables of GEOILBENT
were converted to long term debt. The Company's proportionate share of the
converted payables is $1.5 million.
During the year ended December 31, 1996, the Company acquired Benton Offshore
China Company, formerly Crestone Energy Corporation, a privately held
corporation headquartered in Denver, Colorado, for 628,142 shares of common
stock and options to purchase 107,571 shares of the Company's common stock at
$7.00 per share, valued in total at $14.6 million.
During the year ended December 31, 1996, $3.2 million principal amount of the
Company's 8% convertible notes and $4.3 million principal amount of the
Company's 8% convertible debentures were retired upon conversion into 275,081
and 435,872 shares of the Company's common stock, respectively.
During the year ended December 31, 1996, the Company financed the purchase of
oil and gas equipment and services in the amount of $0.3 million.
During the year ended December 31, 1996, the Company acquired the partners'
interests in each of the three limited partnerships sponsored by the Company in
exchange for an aggregate of 168,362 shares of the Company's common stock and
warrants to purchase 587,783 shares of common stock at $11.00 per share, with a
total value of $4.0 million.
See accompanying notes to consolidated financial statements.
S-7
<PAGE> 44
44
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Benton Oil and Gas Company (the "Company") engages in the exploration,
development, production and management of oil and gas properties. The Company
conducts its business in Venezuela, Russia, the United States, China, Jordan and
Senegal.
The Company and its former subsidiary, Benton Oil and Gas Company of Louisiana,
participated as the managing general partner of three oil and gas limited
partnerships formed during 1989 through 1991. Under the provisions of the
limited partnership agreements, the Company received compensation as stipulated
therein, and functioned as an agent for the partnerships to arrange for the
management, drilling, and operation of properties, and assumed customary
contingent liabilities for partnership obligations. In January 1996, the Company
acquired the limited partnership interests for an aggregate of 168,362 shares of
common stock and warrants to purchase 587,783 shares of common stock at $11 per
share, and liquidated the partnerships (see Note 2).
The consolidated financial statements include the accounts of the Company and
its subsidiaries. The Company's investment in GEOILBENT, its Russian joint
venture, is accounted for using proportionate consolidation based on the
Company's ownership interest. The Company's investment in Severneftegaz, a
Russian open joint stock company, is accounted for using the equity method
because of the significant influence the Company exercises over its operations
and management. All intercompany profits, transactions and balances have been
eliminated. The Company accounts for its investment in GEOILBENT and
Severneftegaz based on a fiscal year ending September 30. The consolidated
financial statements have been adjusted to reflect the Company's capital
contribution of $2.0 million made to GEOILBENT in December 1998.
During 1998, the Company instituted a capital expenditure program which
minimized expenditures to those that the Company believed were necessary in
order to maintain current producing properties.
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuation in response to change in supply, market uncertainty and a variety of
factors beyond the Company's control.
The Company believes its current cash and cash to be provided by operating
activities will be sufficient to meet the Company's liquidity needs for routine
operations and to service its outstanding debt through 1999. The Company
continues to evaluate and review strategic alternatives and has engaged J.P.
Morgan Securities, Inc. to advise the Company related to these alternatives. If
market conditions worsen and future cash requirements are greater than the
Company's financial resources, the Company intends to pursue strategic joint
ventures or alliances with other industry partners, sell property interests,
merge or combine with another entity, or issue debt or equity securities.
REVENUE RECOGNITION
Oil and gas revenue is recognized when title passes to the customer.
CASH AND CASH EQUIVALENTS
Cash equivalents include money market funds and short term certificates of
deposit with original maturity dates of less than three months.
RESTRICTED CASH
Restricted cash represents cash and cash equivalents used as collateral for
financing and letter of credit agreements and is classified as current or
non-current based on the terms of the agreements.
S-8
<PAGE> 45
45
MARKETABLE SECURITIES
Marketable securities are carried at amortized cost. The marketable securities
the Company may purchase are limited to those defined as Cash Equivalents in the
indentures for its senior unsecured notes. Cash Equivalents may be comprised of
high-grade debt instruments, demand or time deposits, bankers' acceptances and
certificates of deposit or acceptances of large U.S. financial institutions and
commercial paper of highly rated U.S. corporations, all having maturities of no
more than 180 days. The Company's marketable securities at cost, which
approximates fair value, at December 31, 1998, consisted of $41.2 million in
commercial paper and at December 31, 1997, consisted of $12.6 million in
government backed notes, $139.4 million in commercial paper, $2.4 million in
agreements to repurchase treasury securities and $2.0 million in bankers'
acceptances.
ACCOUNTS AND NOTES RECEIVABLE
The Company has recorded an allowance for doubtful accounts of $3.2 million and
$0.3 million related to employee notes and accounts receivable and other
accounts receivable at December 31, 1998 and 1997, respectively (see Note 15).
OTHER ASSETS
Other assets consist principally of costs associated with the issuance of long
term debt. Debt issuance costs are amortized on a straight-line basis over the
life of the debt.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for oil and gas
properties with costs accumulated in cost centers on a country by country basis.
All costs associated with the acquisition, exploration, and development of oil
and gas reserves are capitalized as incurred, including exploration overhead of
$2.4 million, $1.9 million and $1.4 million for the years ended December 31,
1998, 1997 and 1996, respectively. Only overhead that is directly identified
with acquisition, exploration or development activities is capitalized. All
costs related to production, general corporate overhead and similar activities
are expensed as incurred.
The costs of unproved properties are excluded from amortization until the
properties are evaluated. The Company regularly evaluates its unproved
properties on a country by country basis for possible impairment. If the Company
abandons all exploration efforts in a country where no proved reserves are
assigned, all exploration and acquisition costs associated with the country are
expensed. During 1998, the Company recognized $6.1 million of impairment expense
associated with certain exploration activities. Due to the unpredictable nature
of exploration drilling activities, the amount and timing of impairment expenses
are difficult to predict with any certainty. The principal portion of such
costs, excluding those related to the acquisition of Benton Offshore China
Company, is expected to be included in amortizable costs during the next two to
three years. The ultimate timing of when the costs related to the acquisition of
Benton Offshore China Company will be included in amortizable costs is
uncertain.
Excluded costs at December 31, 1998 consisted of the following by year incurred
(in thousands):
<TABLE>
<CAPTION>
TOTAL 1998 1997 1996 PRIOR TO 1996
----- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C>
Property acquisition costs $ 15,106 - - $ 15,106 -
Exploration costs 20,122 14,629 4,181 496 816
-------- -------- ------- -------- --------
$ 35,228 $ 14,629 $ 4,181 $ 15,602 $ 816
======== ======== ======= ======== ========
</TABLE>
All capitalized costs and estimated future development costs (including
estimated dismantlement, restoration and abandonment costs) of proved reserves
are depleted using the units of production method based on the total proved
reserves of the country cost center. Depletion expense attributable to the
Venezuelan cost center for the years ended December 31, 1998, 1997 and 1996 was
$31.8 million, $43.6 million and $29.5 million ($2.62, $2.83 and $2.33 per
equivalent barrel), respectively. Depletion expense attributable to the Russian
cost center for the years ended December 31, 1998, 1997 and 1996 was $2.5
million, $3.1 million and $2.7 million ($2.68, $3.50 and $3.59 per equivalent
barrel), respectively. Depletion expense attributable to the United States cost
center for the year ended December 31, 1996 was $1.7 million ($6.55 per
equivalent barrel).
S-9
<PAGE> 46
46
A gain or loss is recognized on sales of oil and gas properties only when the
sale involves a significant change in the relationship between costs and the
value of proved reserves or the underlying value of unproved property.
Depreciation of furniture and fixtures is computed using the straight-line
method with depreciation rates based upon the estimated useful life of the
property, generally 5 years. Leasehold improvements are depreciated over the
life of the applicable lease. Depreciation expense was $1.3 million, $0.9
million and $0.5 million for the years ended December 31, 1998, 1997 and 1996,
respectively.
The major components of property and equipment at December 31 are as follows (in
thousands):
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Proved property costs $438,972 $331,645
Costs excluded from amortization 35,228 31,588
Oilfield inventories 9,294 4,523
Furniture and fixtures 9,608 5,734
-------- --------
493,102 373,490
Accumulated depletion, impairment and depreciation (339,636) (100,293)
======== ========
$153,466 $273,197
======== ========
</TABLE>
The Company performs a quarterly cost center ceiling test of its oil and gas
properties under the full cost accounting rules of the Security and Exchange
Commission. During 1998, due to declines in world crude oil prices, the ceiling
tests resulted in write-downs of oil and gas properties in the Venezuela and
Russia cost centers of $187.8 million and $10.1 million, respectively.
TAXES ON INCOME
Deferred income taxes reflect the net tax effects, calculated at currently
enacted rates, of (a) future deductible/taxable amounts attributable to events
that have been recognized on a cumulative basis in the financial statements or
income tax returns and (b) operating loss and tax credit carryforwards. A
valuation allowance for deferred tax assets is recorded when it is more likely
than not that the benefit from the deferred tax asset will not be realized.
FOREIGN CURRENCY
The Company has significant operations outside of the United States, principally
in Russia and Venezuela. Both Russia and Venezuela are considered highly
inflationary economies. As a result, operations in those countries are
remeasured in United States dollars, and all currency gains or losses are
recorded in the statement of income. The Company attempts to manage its
operations in a manner to reduce its exposure to foreign exchange losses.
However, there are many factors which affect foreign exchange rates and
resulting exchange gains and losses, many of which are beyond the influence of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the United States dollar. It is not possible to predict
the extent to which the Company may be affected by future changes in exchange
rates.
FINANCIAL INSTRUMENTS
The Company's financial instruments that are exposed to concentrations of credit
risk consist primarily of its cash equivalents, marketable securities and
accounts receivable. The Company's short term investments are placed with a wide
array of financial institutions with high credit ratings. This diversified
investment policy limits the Company's exposure both to credit risk and to
concentrations of credit risk.
Accounts receivable result from oil and gas exploration and production
activities. A majority of the Company's customers and partners are engaged in
the oil and gas business. One customer purchased 91%, 94% and 93% of the
Company's oil production during the years ended December 31, 1998, 1997 and
1996, respectively. Although the Company does not currently foresee a credit
risk associated with these receivables, repayment is dependent upon the
financial stability of the customer.
S-10
<PAGE> 47
47
The Company's financial instruments consist primarily of cash and cash
equivalents, accounts receivable and payable, marketable securities, short term
borrowings and long term debt. The book values of all financial instruments,
other than long term debt, are representative of their fair values due to their
short term maturities. The carrying values of the Company's long term debt,
except for the senior unsecured notes, are considered to approximate their fair
values because their interest rates are comparable to current rates available to
the Company. The aggregate fair value of the Company's senior unsecured notes,
based on the last trading prices at December 31, 1998 and 1997, was
approximately $149.9 million and $246.7 million, respectively.
TREASURY STOCK
In June 1997, the Board of Directors instituted a treasury stock repurchase
program under which the Company is authorized to purchase up to 1,500,000 shares
of its common stock. The shares will be used for re-issuance in connection with
the Company's employee stock option plan, treasury stock or for other corporate
purposes to be determined in the future. During 1997, the Company repurchased
50,000 shares at an average price of $13.99 per share.
COMPREHENSIVE INCOME
Statement of Financial Accounting Standards No. 130 ("SFAS 130") requires that
all items that are required to be recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements. This
requirement is effective for the Company in 1998. However, the Company did not
have any items of other comprehensive income during the three years ended
December 31, 1998 and, in accordance with SFAS 130, has not provided a separate
statement of comprehensive income.
OPERATING SEGMENTS
Statement of Financial Accounting Standards No. 131 ("SFAS 131") requires that a
public business enterprise report financial and descriptive information about
its reportable operating segments. Operating segments are components of an
enterprise about which separate financial information is available that is
evaluated regularly by the Company's chief operating decision makers in deciding
how to allocate resources and in assessing performance. This requirement is
effective for the Company in 1998 (see Note 8).
MINORITY INTERESTS
The Company records a minority interest attributable to the minority
shareholders of its subsidiaries. The minority interests in net income and
losses are subtracted or added to arrive at consolidated net income. During
1998, losses attributable to the minority shareholders of Benton-Vinccler, a
subsidiary owned 80% by the Company, exceeded their interest in equity capital.
Accordingly, $3.5 million of Benton-Vinccler's 1998 loss attributable to the
minority shareholders has been included in the consolidated net loss of the
Company.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain items in 1997 and 1996 have been reclassified to conform to the 1998
financial statement presentation.
S-11
<PAGE> 48
48
NOTE 2 - ACQUISITIONS AND SALES
In April 1996, the Company sold its remaining interests in the West Cote Blanche
Bay, Rabbit Island and Belle Isle Fields located in the Gulf Coast of Louisiana
for approximately $35.4 million, resulting in a gain of approximately $7.2
million after adjustments for revenues and expenses subsequent to the effective
date of December 31, 1995 and satisfaction of a net profits interest associated
with the properties. In conjunction with this sale and to obtain the required
consents for such sale, the Company agreed to repay $35 million in senior
unsecured notes and a $5 million revolving credit facility which was secured in
part by these properties. Debt prepayment premiums and related costs totaling
approximately $11.0 million ($10.1 million net of tax benefits) were recognized
as an extraordinary charge in 1996.
In January 1996, the Company completed an exchange offer under which it issued
an aggregate of 168,362 shares of common stock and warrants to purchase 587,783
shares of common stock at $11 per share in exchange for all outstanding limited
partnership interests in the three remaining limited partnerships sponsored by
the Company. The shares of common stock were valued at $1.9 million (based upon
the current market price at the time of the offer), which was allocated to oil
and gas properties. Substantially all of the oil and gas properties were
immediately sold at their approximate book value. The warrants, issued as an
inducement to the participants to accept the exchange offer, were valued at
$3.64 per warrant (an aggregate of $2.1 million), which was charged to expense
in 1996.
NOTE 3 - LONG TERM DEBT
Long term debt consists of the following at December 31 (in thousands):
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Senior unsecured notes with interest at 9.375%.
See description below. $ 105,000 $ 105,000
Senior unsecured notes with interest at 11.625%.
See description below. 125,000 125,000
Benton-Vinccler credit facility with interest at
LIBOR plus 6.125%. Collateralized by a time deposit of the Company
earning approximately LIBOR plus 5.75%.
See description below. 50,000 50,000
Reserve-based loans with average interest
rate of LIBOR plus 5.25%. See description below. 6,453 -
GEOILBENT credit facility collateralized by a time deposit of the
Company earning approximately 5.6%. See description below. 1,624 -
Other 350 1,479
--------- ---------
288,427 281,479
Less current portion 215 1,463
--------- ---------
$ 288,212 $ 280,016
========= =========
</TABLE>
In November 1997, the Company issued $115 million in 9.375% senior unsecured
notes due November 1, 2007, of which the Company subsequently repurchased $10
million at their par value. In May 1996, the Company issued $125 million in
11.625% senior unsecured notes due May 1, 2003. Interest on the notes is due May
1 and November 1 of each year. The indenture agreements provide for certain
limitations on liens, additional indebtedness, certain investments and capital
expenditures, dividends, mergers and sales of assets. At December 31, 1998, the
Company was in compliance with all covenants of the indentures.
In August 1996, Benton-Vinccler entered into a $50 million, long term credit
facility with Morgan Guaranty Trust Company of New York ("Morgan Guaranty") to
repay the balance outstanding under a short term credit facility and to repay
certain advances received from the Company. The credit facility is
collateralized in full by a time deposit of the Company, bears interest at LIBOR
plus 6.125% and matures in August 2001. The Company receives interest on its
time deposit and a security fee on the outstanding principal of the loan, for a
combined total of approximately LIBOR plus 5.75%. The loan arrangement contains
no restrictive covenants and no financial ratio covenants.
GEOILBENT (owned 34% by the Company) has borrowed $19.0 million under parallel
reserve-based loan agreements with the European Bank for Reconstruction and
Development ("EBRD") and International Moscow Bank ("IMB"). EBRD and IMB have
agreed to lend up to a total of $65 million to GEOILBENT based on achieving
certain reserve and production milestones. Under these loan agreements, the
Company and other shareholders of GEOILBENT have significant support
obligations. Each shareholder shall be jointly and severally liable to EBRD and
IMB for any losses, damages, liabilities,
S-12
<PAGE> 49
49
costs, expenses and other amounts suffered or sustained arising out of any
breach by any shareholder of its support obligations. The loans bear an average
interest rate of LIBOR plus 5.25% payable on January 27 and July 27 each year.
Principal payments will be due in varying installments every six months
beginning January 27, 2000 until July 27, 2004. The loan agreements require that
GEOILBENT meet certain financial ratios and covenants, including a minimum
current ratio, and provides for certain limitations on liens, additional
indebtedness, certain investment and capital expenditures, dividends, mergers
and sales of assets. The Company's share of the amounts borrowed under the loan
agreements was $6.5 million at December 31, 1998.
In October 1995, GEOILBENT entered into an agreement with Morgan Guaranty for a
credit facility under which the Company provides cash collateral for the loans
to GEOILBENT. The credit facility is renewable annually. Loans outstanding under
the credit facility bear interest at either LIBOR plus 0.75%, subject to certain
adjustments, or the Morgan Guaranty prime rate plus 2%, whichever is selected at
the time a loan is made. At December 31, 1997, the Company's proportionate share
of the outstanding borrowings was $1.5 million and was classified as short term.
In conjunction with GEOILBENT's reserve-based loan agreements with the EBRD and
IMB, repayment of the credit facility was subordinated to payments due to the
EBRD and IMB and, accordingly, the credit facility was reclassified as long term
in 1998. The credit facility contains no restrictive covenants and no financial
ratio covenants.
The principal payment requirements for the long term debt outstanding at
December 31, 1998 are as follows for the years ending December 31 (in
thousands):
<TABLE>
<S> <C>
1999 $ 215
2000 136
2001 50,000
2002 993
2003 126,720
Subsequent Years 110,363
---------
$ 288,427
=========
</TABLE>
NOTE 4 - COMMITMENTS AND CONTINGENCIES
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties and that it paid a
price in excess of the fair value of the property. A trial date has been
scheduled for August 9, 1999 and discovery is ongoing, but incomplete. The
Company intends to vigorously contest the suit, and in management's opinion it
is too early to assess the probability of an unfavorable outcome.
In the normal course of its business, the Company may periodically become
subject to actions threatened or brought by its investors or partners in
connection with the operation or development of its properties or the sale of
securities. Prior to 1992, the Company was engaged in the formation and
operation of oil and gas limited partnership interests. In 1992, the Company
ceased raising funds through such sales. Certain limited partners in limited
partnerships sponsored by the Company have brought an action against the Company
in connection with the Company's operation of the limited partnerships as
managing general partner. The plaintiffs seek actual and punitive damages for
alleged actions and omissions by the Company in operating the partnerships and
alleged misrepresentations made by the Company in selling the limited
partnership interests. In May 1995, the Company agreed to a binding arbitration
proceeding with respect to such claims. Based on the plaintiffs' failure to
pursue the arbitration, the American Arbitration Association dismissed the case
on November 25, 1998, but gave the plaintiffs until February 23, 1999, to obtain
a court order compelling arbitration. To date, the plaintiffs have neither
sought nor obtained such a court order.
The Company is also subject to ordinary litigation that is incidental to its
business, none of which are expected to have a material adverse effect on the
Company's financial statements.
In May 1996, the Company entered into an agreement with Morgan Guaranty which
provided for an $18 million cash collateralized 5-year letter of credit to
secure the Company's performance of the minimum exploration work program
required in the Delta Centro Block in Venezuela. In December 1998, the letter of
credit was reduced to $11.2 million as a result of expenditures made related to
the exploration work program.
S-13
<PAGE> 50
50
The Company has employment contracts with 4 senior management personnel which
provide for annual base salaries, bonus compensation and various benefits. The
contracts provide for the continuation of salary and benefits for the respective
terms of the agreements in the event of termination of employment without cause.
These agreements expire at various times from July 10, 1999 to June 1, 2001.
The Company has also entered into employment agreements with 8 individuals,
which provide for certain severance payments in the event of a change of
control of the Company and subsequent termination by the employees for good
reason.
The Company has also entered into various exploration and development contracts
in various countries which require minimum expenditures, some of which required
that the Company secure its commitments by providing letters of credit (see
Notes 10, 11, 13, 14). The Company has entered into equity acquisition
agreements in Russia which call for the Company to provide or arrange for
certain amounts of credit financing in order to remove sale and transfer
restrictions on the equity acquired or to maintain ownership in such equity (see
Note 9).
The Company has entered into a 15-year lease agreement for office space in
Carpinteria, California. The Company has leased 50,000 square feet for
approximately $74,000 per month with annual rent adjustments based on certain
changes in the Consumer Price Index. The Company has entered into a sublease
agreement for a portion of the office space which is not currently needed for
operations. The Company has also entered into a sublease agreement for the
office space that it previously occupied. Rents for the subleases approximate
the Company's lease costs of these facilities.
The Company's aggregate rental commitments for noncancellable agreements at
December 31, 1998 are as follows (in thousands):
<TABLE>
<CAPTION>
Minimum Lease Sublease
Commitments Income
----------- ------
<C> <C> <C>
1999 $ 1,737 $ (780)
2000 1,540 (761)
2001 1,437 (744)
2002 1,224 (744)
2003 1,224 (621)
Thereafter 8,907 (338)
------- -------
$16,069 $(3,988)
======= =======
</TABLE>
Rental expense was $2.1 million, $2.0 million and $2.2 million for the years
ended December 31, 1998, 1997 and 1996, respectively. Sublease income was $0.3
million and $0.2 million for the years ended December 31, 1998 and 1996. The
Company had no sublease income for the year ended December 31, 1997.
NOTE 5 - TAXES ON INCOME
The tax effects of significant items comprising the Company's net deferred
income taxes as of December 31, 1998 and 1997 are as follows (in thousands):
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Deferred tax assets:
Operating loss carryforwards $ 33,446 $ 24,529
Difference in basis of property 6,757 -
Other 10,250 338
Valuation allowance (47,375) (13,841)
-------- ---------
Total 3,078 11,026
-------- ---------
Deferred tax liabilities:
Difference in basis of property - (35,837)
Other (102) -
-------- ---------
Net deferred tax asset (liability) $ 2,976 $ (24,811)
======== =========
</TABLE>
S-14
<PAGE> 51
51
The components of income before income taxes and minority interest are as
follows (in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Income (loss) before income taxes
United States $ (54,783) $ (5,989) $ 3,062
Foreign (175,912) 47,848 65,787
--------- -------- --------
Total $(230,695) $ 41,859 $ 68,849
========= ======== ========
</TABLE>
The provision for income taxes consisted of the following at December 31, (in
thousands):
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Current:
United States $ 1,970 $ 4,617 $ 2,282
Foreign 1,597 4,728 1,547
--------- ------- -------
3,567 9,345 3,829
--------- ------- -------
Deferred:
United States 3,573 (3,573) -
Foreign (31,360) 11,705 16,679
--------- ------- -------
(27,787) 8,132 16,679
--------- ------- -------
$ (24,220) $17,477 $20,508
========= ======= =======
</TABLE>
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):
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Computed tax expense at the statutory rate $ (80,743) $14,651 $24,097
State income taxes, net of federal effect - 1,072 1,249
Rate differentials for foreign income 21,800 (314) (4,800)
Change in valuation allowance and other 34,723 2,068 (38)
--------- ------- -------
Income tax expense (benefit) $ (24,220) $17,477 $20,508
========= ======= =======
</TABLE>
Rate differentials for foreign income result from tax rates different from the
U.S. tax rate being applied in foreign jurisdictions and from the effect of
foreign currency devaluation in foreign subsidiaries which use the U.S. dollar
as their functional currency.
At December 31, 1998 the Company had, for federal income tax purposes, operating
loss carryforwards of approximately $90 million, expiring in the years 2003
through 2018. If the carryforwards are ultimately realized, approximately $13
million will be credited to additional paid-in capital for tax benefits
associated with deductions for income tax purposes related to stock options.
The Company does not provide deferred income taxes on undistributed earnings of
international consolidated subsidiaries for possible future remittances as all
such earnings are reinvested as part of the Company's ongoing business.
NOTE 6 - STOCK OPTIONS
The Company adopted its 1988 Stock Option Plan in December 1988 authorizing
options to acquire up to 418,824 shares of common stock. Under the plan,
incentive stock options ("ISOs") were granted to a key employee and other
non-qualified stock options ("NQSOs"), stock or bonus rights were granted to
other key employees, directors, independent contractors and consultants at
prices equal to or below market price, exercisable over various periods. The
remaining options to purchase 80,000 shares of common stock for $4.89 per share
were exercised during 1995. During 1989, the Company adopted its 1989
Nonstatutory Stock Option Plan covering 2,000,000 shares of common stock which
were granted to key employees, directors, independent contractors and
consultants at prices equal to or below market prices, exercisable over various
periods. The plan was amended during 1990 to add 1,960,000 shares of common
stock to the plan.
S-15
<PAGE> 52
52
In September 1991, the Company adopted the 1991-1992 Stock Option Plan and the
Directors' Stock Option Plan. The 1991-1992 Stock Option Plan, as amended in
1996 and 1997, permits the granting of stock options to purchase up to 4,800,000
shares of the Company's common stock in the form of ISOs and NQSOs to officers
and employees of the Company. Options may be granted as ISOs, NQSOs or a
combination of each, with exercise prices not less than the fair market value of
the common stock on the date of the grant. The amount of ISOs that may be
granted to any one participant is subject to the dollar limitations imposed by
the Internal Revenue Code of 1986, as amended. In the event of a change in
control of the Company, all outstanding options become immediately exercisable
to the extent permitted by the 1991-1992 Stock Option Plan. All options granted
to date under the 1991-1992 Stock Option Plan vest ratably over a three-year
period from their dates of grant and expire ten years from grant date or one
year after retirement, if earlier. Subsequent to shareholder approval of the
1998 Stock-Based Incentive Plan discussed below, the Board of Directors of the
Company terminated future grants under the 1991-1992 Stock Option Plan.
The Directors' Stock Option Plan permits the granting of nonqualified stock
options ("Director NQSOs") to purchase up to 400,000 shares of common stock to
nonemployee directors of the Company. Upon election as a director and annually
thereafter, each individual who serves as a nonemployee director automatically
is granted an option to purchase 10,000 shares of common stock at a price not
less than the fair market value of common stock on the date of grant. All
Director NQSOs vest automatically on the date of the grant of the options, and
at December 31, 1998, options to purchase 250,000 shares of common stock were
both outstanding and exercisable.
In June 1998, the shareholders of the Company approved the adoption of the 1998
Stock-Based Incentive Plan. The 1998 Stock-Based Incentive Plan authorizes up to
1,400,000 shares of the Company's common stock for grants of non-qualified and
incentive stock options, stock appreciation rights, restricted stock awards and
bonus stock awards to employees of the Company or its subsidiaries or associated
companies. The exercise price of stock options granted under the plan must be no
less than the fair market value of the Company's common stock on the date of
grant. The total number of shares for which awards may be made to any one
participant during any calendar year cannot exceed 500,000 shares, as adjusted
for any changes in capitalization, such as stock splits. In the event of a
change in control of the Company, all outstanding options become immediately
exercisable to the extent permitted by the plan. All options granted to date
under the 1998 Stock-Based Incentive Plan vest ratably over a three-year period
from their dates of grant and expire ten years from grant date or one year after
retirement, if earlier.
A summary of the status of the Company's stock option plans as of December 31,
1998, 1997 and 1996 and changes during the years ending on those dates is
presented below (shares in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
--------------------------- ---------------------------- ---------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
PRICE SHARES PRICE SHARES PRICE SHARES
----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of the $11.78 3,563 $10.78 3,037 $ 8.04 3,342
year:
Options granted 8.62 513 14.32 889 19.33 658
Options exercised 7.77 (81) 6.61 (224) 6.69 (886)
Options cancelled 13.88 (283) 14.41 (139) 12.14 (77)
----- ----- -----
Outstanding at end of the year 11.27 3,712 11.78 3,563 10.78 3,037
===== ===== =====
Exercisable at end of the year 10.63 2,648 9.43 2,206 7.90 1,887
===== ===== =====
</TABLE>
Significant option groups outstanding at December 31, 1998 and related weighted
average price and life information follow (shares in thousands):
<TABLE>
<CAPTION>
NUMBER OUTSTANDING WEIGHTED-AVERAGE WEIGHTED- NUMBER WEIGHTED-
RANGE OF AT REMAINING AVERAGE EXERCISABLE AT AVERAGE
EXERCISE PRICES DECEMBER 31, 1998 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 1998 EXERCISE PRICE
--------------- ----------------- ---------------- -------------- ----------------- --------------
<S> <C> <C> <C> <C> <C>
$ 2.39 52 1.2 Years 2.39 52 2.39
4.89-7.00 789 3.8 Years 5.57 764 5.54
7.25-11.00 1,208 5.8 Years 8.83 828 8.86
11.50-16.50 1,107 7.9 Years 13.66 658 14.00
17.38-24.13 556 8.1 Years 20.75 346 20.96
----- -----
3,712 2,648
===== =====
</TABLE>
S-16
<PAGE> 53
53
The weighted average fair value of the stock options granted from the 1998
Stock-Based Incentive Plan, 1991-1992 Stock Option Plan and the Directors' Stock
Option Plan during 1998, 1997 and 1996 was $6.30, $9.83, $13.10 respectively.
The fair value of each stock option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following weighted average
assumptions used:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Expected life 9.1 years 9.0 years 8.6 years
Risk-free interest rate 5.5% 6.0% 6.2%
Volatility 62% 54% 54%
Dividend Yield 0% 0% 0%
</TABLE>
The Company accounts for stock-based compensation in accordance with APB 25 and
related interpretations, under which no compensation cost has been recognized
for stock option awards. Had compensation cost for the plans been determined
consistent with SFAS 123, the Company's pro forma net income and earnings per
share for 1998, 1997 and 1996 would have been as follows (in thousands, except
per share data):
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Net Income (loss):
Income (loss) before extraordinary charge $ (190,581) $13,343 $36,083
Extraordinary charge - - 10,075
---------- ------- -------
Net income (loss) $ (190,581) $13,343 $26,008
========== ======= =======
Net income (loss) per common share:
Basic:
Income (loss) before extraordinary charge $ (6.45) $ 0.46 $ 1.33
Extraordinary charge - - 0.37
---------- ------- -------
Net income (loss) $ (6.45) $ 0.46 $ 0.96
========== ======= =======
Diluted:
Income (loss) before extraordinary charge $ (6.45) $ 0.44 $ 1.22
Extraordinary charge - - 0.34
---------- ------- -------
Net income (loss) $ (6.45) $ 0.44 $ 0.88
========== ======= =======
</TABLE>
In connection with the acquisition of Benton Offshore China Company by the
Company in December 1996, the Company adopted the Benton Offshore China Company
1996 Stock Option Plan. Under the plan, Benton Offshore China Company is
authorized to issue up to 107,571 options to purchase the Company's common stock
for $7.00 per share. The plan was adopted in substitution of Benton Offshore
China Company's stock option plan, and all options to purchase shares of Benton
Offshore China Company common stock were replaced under the plan by options to
purchase shares of the Company's common stock. All options were issued upon the
acquisition of Benton Offshore China Company and vested upon issuance. At
December 31, 1998, options to purchase 74,427 shares of common stock were both
outstanding and exercisable.
In addition to options issued pursuant to the plans, options have been issued to
individuals other than officers, directors or employees of the Company at prices
ranging from $10.88 to $11.88 which vest over three to four years. At December
31, 1998, a total of 208,500 options issued outside the plans were outstanding,
201,834 of which were vested.
NOTE 7 - STOCK WARRANTS
During the years ended December 31, 1996 and 1995, the Company issued a total of
587,783 and 125,000 warrants, respectively. Each warrant entitles the holder to
purchase one share of common stock at the exercise price of the warrant.
Substantially all the warrants are immediately exercisable upon issuance.
In July 1994, the Company issued warrants entitling the holder to purchase a
total of 150,000 shares of common stock at $7.50 per share, subject to
adjustment in certain circumstances that are exercisable on or before July 2004.
50,000 warrants were immediately exercisable, and 50,000 warrants became
exercisable each July in 1995 and 1996. During the year ended December 31, 1996,
142,000 of these warrants were exercised. In September 1994, 250,000 warrants
were issued in connection with the issuance of $15 million in senior unsecured
notes, and in December 1994, 50,000 warrants were issued in connection with a
revolving secured credit facility.
In June 1995, 125,000 warrants were issued in connection with the issuance of
$20 million in senior unsecured notes.
S-17
<PAGE> 54
54
In January 1996, 587,783 warrants were issued in connection with an exchange
offer under which the Company acquired the outstanding limited partnership
interests in three limited partnerships sponsored by the Company (see Note 2).
During the years ended December 31, 1997 and 1996, 1,578 and 9,215,
respectively, of the warrants were exercised. In November 1998, the Company
extended by one year the expiration date of these warrants to January 18, 2000
and the Company recorded $135,000 of expense as a result of this warrant
extension.
The dates the warrants were issued, the expiration dates, the exercise prices
and the number of warrants issued and outstanding at December 31, 1998 were
(shares in thousands):
<TABLE>
<CAPTION>
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING
----------- --------------- -------------- ------ -----------
<S> <C> <C> <C> <C>
July 1994 July 2004 $ 7.50 150 8
September 1994 September 2002 9.00 250 250
December 1994 December 2004 12.00 50 50
June 1995 June 2007 17.09 125 125
January 1996 January 2000 11.00 588 577
----- -----
1,163 1,010
===== =====
</TABLE>
NOTE 8 - OPERATING SEGMENTS
The Company regularly allocates resources to and assesses the performance of its
operations by segments that are organized by unique geographic and operating
characteristics. The segments are organized in order to manage regional
business, currency and tax related risks and opportunities. Revenues from the
Venezuela and Russia operating segments are derived primarily from the
production and sale of oil. Revenues from USA and Other are derived primarily
from interest earnings on various investments and consulting revenues.
Operations included under the heading "USA and Other" include corporate
management, exploration activities, cash management and financing activities
performed in the United States and other countries which do not meet the
requirements for separate disclosure. All intersegment revenues, expenses and
receivables are eliminated in order to reconcile to consolidated totals.
Corporate general and administrative and interest expenses are included in the
USA and Other segment and are not allocated to other operating segments. The
Company's investment in Severneftegaz has been included in the Russia operating
segment.
<TABLE>
<CAPTION>
USA AND INTER-SEGMENT
1998 (in thousands) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- ------------------- --------- ------ ----- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenue
Oil and gas sales $ 82,215 $ 8,059 $ (3) - $ 90,271
Net gain on exchange rates 1,741 5,990 26 - 7,757
Investment earnings and other 806 205 14,014 (905) 14,120
Intersegment revenues - - 8,211 (8,211) -
-------- -------- -------- ---------- ---------
Total revenues 84,762 14,254 22,248 (9,116) 112,148
-------- -------- -------- ---------- ---------
Expenses
Lease operating costs and production
taxes 39,069 5,626 (20) - 44,675
Depletion, depreciation and
amortization 32,532 2,481 625 - 35,638
General and administrative 6,656 1,449 17,524 - 25,629
Interest 7,261 901 25,651 (905) 32,908
Intersegment expenses 8,211 - - (8,211) -
-------- -------- -------- ---------- ---------
Total expenses 93,729 10,457 43,780 (9,116) 138,850
-------- -------- -------- ---------- ---------
Income (loss) before income taxes (8,967) 3,797 (21,532) - (26,702)
Income taxes (29,955) 191 5,544 - (24,220)
-------- -------- -------- ---------- ---------
Operating segment income (loss) 20,988 3,606 (27,076) - (2,482)
Write down and impairment of oil and
gas properties (187,811) (10,100) (6,082) - (203,993)
Minority interest 22,895 - - - 22,895
-------- -------- -------- ---------- ---------
Net income (loss) $(143,928) $ (6,494) $(33,158) - $(183,580)
======== ======== ======== ========== =========
Capital expenditures $ 84,453 $ 18,009 $ 17,497 - $ 119,959
======== ======== ======== ========== =========
Total assets $103,419 $ 66,189 $228,844 $ (59,831) $ 338,621
======== ======== ======== ========== =========
</TABLE>
S-18
<PAGE> 55
55
<TABLE>
<CAPTION>
USA AND INTER-SEGMENT
1997 (in thousands) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- ------------------- --------- ------ ----- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues
Oil and gas sales $ 154,119 $ 9,925 $ (87) - $ 163,957
Net gain on exchange rates 2,010 274 1 - 2,285
Investment earnings and other 1,666 182 11,864 (935) 12,777
Intersegment revenues - - 14,605 (14,605) -
--------- -------- --------- --------- ---------
Total revenues 157,795 10,381 26,383 (15,540) 179,019
--------- -------- --------- --------- ---------
Expenses
Lease operating costs and production taxes 34,516 7,349 22 - 41,887
Depletion, depreciation and amortization 44,107 3,079 406 - 47,592
General and administrative 8,708 1,786 12,942 - 23,436
Interest 7,412 166 17,602 (935) 24,245
Intersegment expenses 14,605 - - (14,605) -
--------- -------- --------- --------- ---------
Total expenses 109,348 12,380 30,972 (15,540) 137,160
--------- -------- --------- --------- ---------
Income (loss) before income taxes 48,447 (1,999) (4,589) - 41,859
Income taxes 16,212 220 1,045 - 17,477
--------- -------- --------- --------- ---------
Operating segment income (loss) 32,235 (2,219) (5,634) - 24,382
Minority interest (6,333) - - - (6,333)
--------- -------- --------- --------- ---------
Net income (loss) $ 25,902 $ (2,219) $ (5,634) - $ 18,049
========= ======== ========= ========= =========
Capital expenditures $ 98,498 $ 3,582 $ 7,680 - $ 109,760
========= ======== ========= ========= =========
Total assets $ 265,066 $ 43,611 $ 301,721 $ (26,121) $ 584,277
========= ======== ========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
USA AND INTER-SEGMENT
1996 (in thousands) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- ------------------- --------- ------ ----- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues
Oil and gas sales $136,840 $ 9,047 $ 1,816 - $ 147,703
Net gain on exchange rates 1,793 989 38 - 2,820
Investment earnings and other 829 87 6,676 (224) 7,368
Intersegment revenues - - 15,694 (15,694) -
-------- ------- -------- ------- ---------
Total segment revenues 139,462 10,123 24,224 (15,918) 157,891
Gain on sale of properties - - 7,175 - 7,175
-------- ------- -------- ------- ---------
Total revenues 139,462 10,123 31,399 (15,918) 165,066
-------- ------- -------- ------- ---------
Expenses
Lease operating costs and production taxes 17,669 6,605 244 - 24,518
Depletion, depreciation and amortization 29,822 2,747 1,956 - 34,525
General and administrative 6,188 1,151 11,567 - 18,906
Interest 3,714 550 12,088 (224) 16,128
Intersegment expenses 15,694 - - (15,694) -
-------- ------- -------- ------- ---------
Total expenses 73,087 11,053 25,855 (15,918) 94,077
-------- ------- -------- ------- ---------
Income (loss) before income taxes 66,375 (930) 5,544 - 70,989
Income taxes 17,966 259 2,283 - 20,508
-------- ------- -------- ------- ---------
Operating segment income (loss) 48,409 (1,189) 3,261 - 50,481
Partnership exchange expenses - - (2,140) - (2,140)
Minority interest (9,984) - - - (9,984)
-------- ------- -------- ------- ---------
Income (loss) before extraordinary charge $ 38,425 $(1,189) $ 1,121 - $ 38,357
======== ======= ======== ======= =========
Capital expenditures $ 84,735 $ 6,047 $ 4,715 - $ 95,497
======== ======= ======== ======= =========
</TABLE>
S-19
<PAGE> 56
56
NOTE 9 - RUSSIAN OPERATIONS
In October 1997 and during 1998, GEOILBENT borrowed $10.2 million and $8.8
million, respectively, under parallel reserve-based loan agreements with the
European Bank for Reconstruction and Development and International Moscow Bank.
EBRD and IMB have agreed to lend up to a total of $65 million to GEOILBENT based
on achieving certain reserve and production milestones. The proceeds from the
loans will be used by GEOILBENT to develop the North Gubkinskoye Field in West
Siberia, Russia (see Note 3). At December 31, 1998, the Company's share of
borrowings under these agreements was $6.5 million. In March 1999, GEOILBENT
borrowed an additional $8.3 million; the Company's share of this borrowing was
$2.8 million. Additionally, a subsidiary of the Company recorded an account
receivable for pipe it purchased for $5.0 million and sold to GEOILBENT at cost
for use in the development of the field. The portion of the receivable not
eliminated in consolidation is included in accounts receivable joint interest
and other. During 1996 and 1997, the Company incurred $4.1 million in financing
costs related to the establishment of the EBRD financing, which are recorded in
other assets and are subject to amortization over the life of the facility. In
1998, under an agreement with EBRD, GEOILBENT'S board ratified an agreement to
reimburse the Company for $2.6 million of such costs. However, due to
GEOILBENT'S need for oil and gas investment and the declining prices for crude
oil, the Company has agreed to defer payment of those reimbursements. Of the
original $4.1 million, $1.5 million remains in other assets subject to
amortization, and of the $2.6 million, the Company recorded the portion not
eliminated in consolidation, $1.7 million, as a long-term receivable at December
31, 1998.
For the period January 1 through June 30, 1996, the Company recorded an expense
for a Russian oil export tariff of $0.8 million. GEOILBENT received a waiver
from the export tariff for 1995. In July 1996, such oil export tariffs were
terminated in conjunction with a loan agreement with the International Monetary
Fund, but in 1999 new oil export tariffs were introduced. Excise, pipeline and
other taxes (including a new oil export tariff introduced in 1999) continue to
be levied on all oil producers and certain exporters. Although the Russian
regulatory environment has become less volatile, the Company is unable to
predict the impact of taxes, duties and other burdens for the future.
In April 1998, the Company signed an agreement to earn a 40% equity interest in
Severneftegaz. Severneftegaz owns the exclusive rights to evaluate, develop and
produce the natural gas, condensate, and oil reserves in the Samburg and
Yevo-Yakha license blocks in West Siberia. The two blocks comprise 837,000 acres
within and adjacent to the Urengoy field, Russia's largest producing natural gas
field. Pursuant to a Cooperation Agreement between the Company and
Severneftegaz, the Company will earn a 40% equity interest in exchange for
providing the initial capital needed to achieve natural gas production. The
Company's capital commitment will be in the form of providing or arranging a
$100 million credit facility for the project, the terms of which have yet to be
finalized, which is expected to be disbursed over the initial two-year
development phase. The Company received fully voting shares representing a 40%
ownership in Severneftegaz that contain restrictions on their sale and transfer.
The Share Disposition Agreement provides for removal of the restrictions as
disbursements are made under the credit facility. As of December 31, 1998, the
Company had loaned $8.3 million to Severneftegaz pursuant to an interim credit
facility, with interest at LIBOR plus 3%, and had earned the right to remove
restrictions from shares representing an approximate 2% equity interest.
Additionally, in December 1998 and January 1999, the Company purchased
additional equity interests in Severneftegaz from another shareholder, bringing
its total interest in unrestricted shares to approximately 9.5% at December 31,
1998 and 17.2% in January 1999. The Company owned a total of 47.5% of voting
shares of Severneftegaz as of December 31, 1998 and a total of 55% of voting
shares as of January 21, 1999. Due to the significant influence it exercises
over the operating and financial policies of Severneftegaz, the Company has
accounted for its interest in Severneftegaz using the equity method. The
Company's share in the equity losses of Severneftegaz were not material for the
year ended December 31, 1998. Certain provisions of Russian corporate law would
effectively require minority shareholder consent in the making of new agreements
between the Company and Severneftegaz, or to the changing of any terms in any
existing agreements, including the conditions upon which the restrictions on the
shares could be removed, between the two such as the Cooperation Agreement and
the Share Disposition Agreement.
NOTE 10 - VENEZUELA OPERATIONS
On July 31, 1992, the Company and its partner, Venezolana de Inversiones y
Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement
to reactivate and further develop three Venezuelan oil fields with Lagoven,
S.A., then one of three exploration and production affiliates of the national
oil company, Petroleos de Venezuela, S.A. ("PDVSA") which have subsequently all
been combined into PDVSA Petroleo y Gas, S.A. (all such parent, subsidiary and
affiliated entities hereinafter referred to as "PDVSA"). The operating service
agreement covers the Uracoa, Bombal and Tucupita fields that comprise the South
Monagas Unit ("Unit"). Under the terms of the operating service agreement,
Benton-Vinccler, C.A. ("Benton-Vinccler"), a corporation owned 80% by the
Company and 20% by Vinccler, is a contractor for
S-20
<PAGE> 57
57
PDVSA and is responsible for overall operations of the Unit, including all
necessary investments to reactivate and develop the fields comprising the Unit.
Benton-Vinccler receives an operating fee in U.S. dollars deposited into a U.S.
commercial bank account for each barrel of crude oil produced (subject to
periodic adjustments to reflect changes in a special energy index of the U.S.
Consumer Price Index) and is reimbursed according to a prescribed formula in
U.S. dollars for its capital costs, provided that such operating fee and cost
recovery fee cannot exceed the maximum dollar amount per barrel set forth in the
agreement (which amount is periodically adjusted to reflect changes in the
average of certain world crude oil prices). The Venezuelan government maintains
full ownership of all hydrocarbons in the fields.
In January 1996, the Company and its bidding partners, Louisiana Land &
Exploration, which has been subsequently acquired by Burlington Resources, Inc.
("Burlington"), and Norcen Energy Resources, LTD, which has been subsequently
acquired by Union Pacific Resources Group Inc. ("UPR"), were awarded the right
to explore and develop the Delta Centro Block in Venezuela. The contract
requires a minimum exploration work program consisting of completing an 839
kilometer seismic survey and drilling three wells to depths of 12,000 to 18,000
feet within five years. PDVSA estimates that this minimum exploration work
program will cost $60 million and requires that the Company and the other
partners each post a performance surety bond or standby letter of credit for its
pro rata share of the estimated work commitment expenditures. The Company has a
30% interest in the exploration venture, with Burlington and UPR each owning a
35% interest. Under the terms of the operating agreement, which establishes the
management company of the project, Burlington will be the operator of the field
and, therefore, the Company will not be able to exercise control of the
operations of the venture. Corporacion Venezolana del Petroleo, S.A., an
affiliate of PDVSA, has the right to obtain a 35% interest in the management
company, which dilutes the voting power of the partners on a pro rata basis. In
July 1996, formal agreements were finalized and executed, and the Company posted
an $18 million standby letter of credit, collateralized in full by a time
deposit of the Company, to secure its 30% share of the minimum exploration work
program (see Note 4). As of December 31, 1998, the Company' share of
expenditures to date was $8.2 million and the standby letter of credit had been
reduced to $11.2 million. During the first quarter of 1999, drilling commenced
on the Jarina-1 X, the first of the Block's exploration wells.
NOTE 11 - CHINA OPERATIONS
In December 1996, the Company acquired Benton Offshore China Company, a
privately held corporation headquartered in Denver, Colorado, for 628,142 shares
of common stock and options to purchase 107,571 shares of the Company's common
stock at $7.00 per share, valued in total at $14.6 million. Benton Offshore
China Company's primary asset is a large undeveloped acreage position in the
South China Sea under a petroleum contract with China National Offshore Oil
Corporation ("CNOOC") of the People's Republic of China for an area known as
Wan'An Bei, WAB-21. Benton Offshore China Company will, as a wholly owned
subsidiary of the Company, continue as the operator and contractor of WAB-21.
Benton Offshore China Company has submitted an exploration program and budget to
CNOOC for 1998. However, due to certain territorial disputes over the
sovereignty of the contract area, it is unclear when such program will commence.
In October 1997, the Company signed a farmout agreement with Shell Exploration
(China) Limited ("Shell") whereby the Company acquired a 50% participation
interest in Shell's Liaohe area onshore exploration project in northeast China.
Shell holds a petroleum contract with China National Petroleum Corporation
("CNPC") to explore and develop the deep rights in the Qingshui Block, a 563
square kilometer area (approximately 140,000 acres) in the delta of the Liaohe
River. Shell will be the operator of the project. In July 1998, the Company paid
to Shell 50% of Shell's prior investment in the Block, which was approximately
$4 million ($2 million to the Company). The Company is required to pay 100% of
the first $8 million of the costs for the phase one exploration period, after
which any development costs will be shared equally. If a commercial well results
from phase one and the Company elects to continue to phase two, then the Company
will pay 100% of the first $8 million of the costs of the second phase of the
exploration period, after which any development costs will be shared equally. If
a commercial well does not result from phase one and the Company elects to
continue to phase two, then the Company and Shell will share costs equally. The
Company and Shell will share costs equally for the third exploration phase, if
any. During the first quarter of 1999, drilling commenced on the Qing-22 Deep
well as a part of the phase one exploration period activities. As of December
31, 1998, the Company had incurred $4.2 million related to the farmout
agreement.
NOTE 12 - SANTA BARBARA OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy, which held 100%
of these leases. The project area covers the Molino, Gaviota and Caliente
Fields, located approximately 35 miles west of Santa Barbara, California. In
consideration of the 40% participation interest in the leases, the Company
became the operator of the project and paid 100% of the first $3.7 million and
53% of the remainder of the costs of
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<PAGE> 58
58
the first well drilled on the block. During 1998, the 2199 #7 exploratory well
was drilled to the Gaviota anticline. Drill stem tests proved to be inconclusive
or non-commercial, and the well was temporarily abandoned for further
evaluation. The Company's share of the drilling and testing of the 2199 #7 well
was $8.5 million. In November 1998, the Company entered into an agreement to
acquire Molino Energy's interest in the leases in exchange for the release of
its joint interest billing obligations of approximately $1.9 million. The
agreement to acquire Molino Energy's interest will be finalized upon the
completion of certain lot splits and the assignment of various permits and
rights.
NOTE 13 - JORDAN OPERATIONS
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which is expected to last
approximately two years. If the Company ultimately elects to continue through
phases two and three, it would be obligated to spend an additional $18 million
over the succeeding six years. During the first quarter of 1998, the Company
reentered two wells and tested two different reservoirs. The WS-9 and WS-10
wells did not result in the production of commercial amounts of hydrocarbons.
The Company will continue to reprocess and remap seismic data and conduct
geological studies on the remaining prospectivity of the block. At December 31,
1998, the Company had incurred $3.7 million related to the PSA.
NOTE 14 - SENEGAL OPERATIONS
In December 1997, the Company signed a memorandum of understanding with Societe
des Petroles du Senegal ("Petrosen"), the state oil company of the Republic of
Senegal, to receive a minimum 45% working interest in and to operate the
approximately one million acre onshore Thies Block in western Senegal. In
addition, the Company obtained exclusive rights from Petrosen to evaluate and
reprocess geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea-Bissau border in the south, and to choose
certain blocks for further data acquisition and exploration drilling. The
Company's working interest in any offshore discovery will be 85% with the
remainder held by Petrosen. The Company's $5.4 million work commitment on the
Thies Block, where Petrosen has recently drilled and completed the Gadiaga #2
discovery well, consists of hooking up the existing well, drilling two
additional wells and constructing a 41-kilometer (approximately 25-mile) gas
pipeline en route to Senegal's main electric generating facility near Dakar. At
December 31, 1998, the Company had incurred $1.7 million related to both the
onshore block and near-offshore acreage.
NOTE 15 - RELATED PARTY TRANSACTIONS
Prior to November 30, 1998 and during 1997 and 1996, the Company made unsecured
loans documented by a promissory note bearing interest at 6% to Mr. A. E.
Benton, its Chief Executive Officer. At December 31,1997 and September 30, 1998,
the balances owed to the Company were $2.0 million and $4.4 million,
respectively. In the fourth quarter of 1998, the Company loaned Mr. Benton an
additional $1.1 million to enable him to reduce and eliminate his outstanding
margin accounts with third parties that were secured by shares of the Company's
stock. The Company then obtained a security interest in those shares of stock,
certain personal real estate and proceeds from certain contractual and stock
option agreements. At December 31, 1998, the $5.5 million owed to the Company by
Mr. Benton, which is documented by a promissory note that bears interest at 6%
and is payable on November 30, 1999, exceeded the value of the collateral,
primarily due to the decline in the price of the Company's stock. As a result,
the Company has recorded an allowance for doubtful accounts of $2.9 million.
Measuring the amount of the allowance requires judgments and estimates, and the
amount eventually realized may differ from the estimate. The portion of the note
secured by the Company's stock and stock options has been presented on the
balance sheet as a deduction from stockholders' equity.
Also during 1998, 1997 and 1996, the Company made loans to Mr. M.B. Wray, its
Vice Chairman, and Mr. J.M. Whipkey, its Chief Financial Officer, each loan
bearing interest at 6% and collateralized by a security interest in personal
real estate. At December 31, 1998, the balances owed to the Company by Mr. Wray
and Mr. Whipkey were $0.6 million and $0.5 million, respectively and at December
31, 1997, the balances owed to the Company by Mr. Wray and Mr. Whipkey were $0.7
million and $0.5 million, respectively.
In addition, other receivables from employees and directors of the Company
amounted to $0.6 million and $0.3 million at December 31, 1998 and 1997,
respectively.
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<PAGE> 59
59
NOTE 16 - EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128 ("SFAS 128") "Earnings per Share." SFAS
128 replaces the presentation of primary earnings per share with a presentation
of basic earnings per share based upon the weighted average number of common
shares for the period. It also requires dual presentation of basic and diluted
earnings per share for companies with complex capital structures. SFAS 128 was
adopted by the Company in December 1997 and earnings per share for all prior
periods have been restated. The numerator (income) and denominator (shares) of
the basic and diluted earnings per share computations for income before
extraordinary charge were (in thousands, except per share amounts):
<TABLE>
<CAPTION>
INCOME SHARES AMOUNT PER SHARE
------ ------ ----------------
<S> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1998
- ------------------------------------
BASIC EPS
Loss available to common stockholders $(183,580) 29,554 $ (6.21)
========= ====== =======
Effect of Dilutive Securities:
Stock options and warrants - -
--------- ------
DILUTED EPS
Loss available to common stockholders $(183,580) 29,554 $ (6.21)
========= ====== =======
FOR THE YEAR ENDED DECEMBER 31, 1997
- ------------------------------------
BASIC EPS
Income available to common stockholders $ 18,049 29,119 $ 0.62
========= ====== =======
Effect of Dilutive Securities:
Stock options and warrants - 1,715
--------- ------
DILUTED EPS
Income available to common stockholders
and assumed conversions $ 18,049 30,834 $ 0.59
========= ====== =======
FOR THE YEAR ENDED DECEMBER 31, 1996
- ------------------------------------
BASIC EPS
Income available to common stockholders $ 38,357 27,088 $ 1.42
========= ====== =======
Effect of Dilutive Securities:
Convertible notes and debentures 33 223
Stock options and warrants - 2,502
--------- ------
DILUTED EPS
Income available to common stockholders $ 38,390 29,813 $ 1.29
========= ====== =======
</TABLE>
For the years ended December 31, 1998, 1997 and 1996, 3,287,084, 581,324 and
135,579 options and warrants, respectively, were excluded from the earnings per
share calculations because they were anti-dilutive.
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<PAGE> 60
60
QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
<TABLE>
<CAPTION>
QUARTER ENDED
---------------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(amounts in thousands, except per share data)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1998
Revenues $ 33,258 $ 28,208 $ 23,879 $ 26,803
Expenses 55,293 89,423 31,817 166,310
-------- -------- -------- ---------
Loss before income taxes and minority
interest (22,035) (61,215) (7,938) (139,507)
Income taxes (670) (7,294) 197 (16,453)
-------- -------- -------- ---------
Loss before minority interest (21,365) (53,921) (8,135) (123,054)
Minority interest (379) (3,878) (296) (18,342)
-------- -------- -------- ---------
Net loss $(20,986) $(50,043) $ (7,839) $(104,712)
======== ======== ======== =========
Net loss per common share:
Basic $ (0.71) $ (1.69) $ (0.27) $ (3.54)
Diluted $ (0.71) $ (1.69) $ (0.27) $ (3.54)
</TABLE>
<TABLE>
<CAPTION>
QUARTER ENDED
---------------------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(amounts in thousands, except per share data)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1997
Revenues $46,299 $40,977 $45,188 $46,555
Expenses 28,966 30,418 36,603 41,173
------- ------- ------- -------
Income before income taxes and
minority interest 17,333 10,559 8,585 5,382
Income taxes 5,984 4,432 4,492 2,569
------- ------- ------- -------
Income before minority interest 11,349 6,127 4,093 2,813
Minority interest 2,721 1,639 1,224 749
------- ------- ------- -------
Net income $ 8,628 $ 4,488 $ 2,869 $ 2,064
======= ======= ======= =======
Net income per common share:
Basic $ 0.30 $ 0.15 $ 0.10 $ 0.07
Diluted $ 0.28 $ 0.15 $ 0.09 $ 0.07
</TABLE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
In accordance with Statement of Financial Accounting Standards No. 69,
"Disclosures About Oil and Gas Producing Activities" ("SFAS 69"), this section
provides supplemental information on oil and gas exploration and production
activities of the Company. Tables I through III provide historical cost
information pertaining to costs incurred in exploration, property acquisitions
and development; capitalized costs; and results of operations. Tables IV through
VI present information on the Company's estimated proved reserve quantities,
standardized measure of estimated discounted future net cash flows related to
proved reserves, and changes in estimated discounted future net cash flows.
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<PAGE> 61
61
TABLE I -TOTAL COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES (IN THOUSANDS):
<TABLE>
<CAPTION>
UNITED STATES
AND
VENEZUELA RUSSIA CHINA OTHER TOTAL
--------- ------ ----- ----- -----
<S> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1998
Development costs $ 75,928 $ 13,276 $ - $ 2,105 $ 91,309
Exploration costs 4,230 3,550 4,024 7,853 19,657
-------- -------- --------- -------- --------
$ 80,158 $ 16,826 $ 4,024 $ 9,958 $110,966
======== ======== ========= ======== ========
YEAR ENDED DECEMBER 31, 1997
Development costs $ 95,791 $ 2,652 $ - $ - $ 98,443
Exploration costs 3,919 33 1,088 5,718 10,758
-------- -------- --------- -------- --------
$ 99,710 $ 2,685 $ 1,088 $ 5,718 $109,201
======== ======== ========= ======== ========
YEAR ENDED DECEMBER 31, 1996
Property acquisition costs $ - $ - $ 15,106 $ 1,139 $ 16,245
Development costs 82,197 6,047 - 1,498 89,742
Exploration costs 1,393 - 279 715 2,387
-------- -------- --------- -------- --------
$ 83,590 $ 6,047 $ 15,385 $ 3,352 $108,374
======== ======== ========= ======== ========
</TABLE>
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES (IN
THOUSANDS):
<TABLE>
<CAPTION>
UNITED STATES
AND
VENEZUELA RUSSIA CHINA OTHER TOTAL
--------- ------ ----- ----- -----
<S> <C> <C> <C> <C> <C>
DECEMBER 31, 1998
Proved property costs $ 371,369 $ 61,520 $ - $ 6,083 $438,972
Costs excluded from amortization 4,315 20,498 10,415 35,228
Oilfield inventories 7,214 2,080 - - 9,294
Less accumulated depletion
and impairment (309,381) (20,857) - (6,083) (336,321)
--------- --------- ------- --------- --------
$ 69,202 $ 47,058 $20,498 $ 10,415 $147,173
========= ========= ======= ========= ========
DECEMBER 31, 1997
Proved property costs $ 283,469 $ 48,176 $ - $ - $331,645
Costs excluded from amortization 7,742 842 16,473 6,531 31,588
Oilfield inventories 3,627 896 - - 4,523
Less accumulated depletion (89,727) (8,276) - - (98,003)
--------- --------- ------- --------- --------
$ 205,111 $ 41,638 $16,473 $ 6,531 $269,753
========= ========= ======= ========= ========
DECEMBER 31, 1996
Proved property costs $ 182,566 $ 45,523 $ - $ - $228,089
Costs excluded from amortization 8,935 809 15,385 858 25,987
Oilfield inventories 5,545 - - - 5,545
Less accumulated depletion (46,143) (5,197) - - (51,340)
--------- --------- ------- --------- --------
$ 150,903 $ 41,135 $15,385 $ 858 $208,281
========= ========= ======= ========= ========
</TABLE>
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<PAGE> 62
62
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (IN
THOUSANDS):
<TABLE>
<CAPTION>
UNITED STATES
AND
VENEZUELA RUSSIA OTHER TOTAL
--------- ------ ----- -----
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1998
Oil and gas revenues $ 82,215 $ 8,059 $ (3) $ 90,271
Expenses:
Lease operating costs and production taxes 39,069 5,626 (20) 44,675
Depletion 31,843 2,474 - 34,317
Write down and impairment of oil and gas
properties 187,811 10,100 6,082 203,993
Income tax benefit (26,793) - - (26,793)
----------- --------- ------- ----------
Total expenses 231,930 18,200 6,062 256,192
----------- --------- ------- ----------
Results of operations from oil and gas
producing activities $ (149,715) $ (10,141) $(6,065) $ (165,921)
=========== ========= ======= ==========
YEAR ENDED DECEMBER 31, 1997
Oil and gas revenues $ 154,119 $ 9,925 $ (87) $ 163,957
Expenses:
Lease operating costs and production taxes 34,516 7,349 22 41,887
Depletion 43,584 3,079 - 46,663
Income tax expense 25,656 - - 25,656
----------- --------- ------- ----------
Total expenses 103,756 10,428 22 114,206
----------- --------- ------- ----------
Results of operations from oil and gas
producing activities $ 50,363 $ (503) $ (109) $ 49,751
=========== ========= ======= ==========
YEAR ENDED DECEMBER 31, 1996
Oil and gas revenues $ 136,840 $ 9,047 $ 4,676 $ 150,563
Expenses:
Lease operating costs and production taxes 17,669 6,605 244 24,518
Depletion 29,523 2,747 1,705 33,975
Income tax expense 24,429 - - 24,429
----------- --------- ------- ----------
Total expenses 71,621 9,352 1,949 82,922
----------- --------- ------- ----------
Results of operations from oil and gas
producing activities $ 65,219 $ (305) $ 2,727 $ 67,641
=========== ========= ======= ==========
</TABLE>
GEOILBENT (owned 34% by the Company) has been included in the consolidated
financial statements based on a fiscal period ending September 30 and,
accordingly, results of operations for oil and gas producing activities in
Russia reflect the years ended September 30, 1998, 1997 and 1996.
In May 1994, the Company entered into a commodity hedge agreement designed to
reduce a portion of the Company's risk from oil price movements through December
31, 1996. Pursuant to the hedge agreement, the Company received $16.82 per Bbl
and paid the average price per Bbl of West Texas Intermediate Light Sweet Crude
Oil with regard to 1,500 Bbl of oil per day for 1996. During the year ended
December 31, 1996 the Company incurred losses of $2.9 million under the hedge
agreement which reduced oil and gas sales. The Company did not enter into any
commodity hedging agreements during 1997 and 1998.
S-26
<PAGE> 63
63
TABLE IV - QUANTITIES OF OIL AND GAS RESERVES
Proved reserves are estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected to
be recovered through existing wells with existing equipment and operating
methods. All Venezuelan reserves are attributable to an operating service
agreement between Benton-Vinccler and PDVSA, under which all mineral rights are
owned by the government of Venezuela.
The Securities and Exchange Commission requires the reserve presentation to be
calculated using year-end prices and costs and assuming a continuation of
existing economic conditions. Proved reserves cannot be measured exactly, and
the estimation of reserves involves judgmental determinations. Reserve estimates
must be reviewed and adjusted periodically to reflect additional information
gained from reservoir performance, new geological and geophysical data and
economic changes. The estimates are based on current technology and economic
conditions, and the Company considers such estimates to be reasonable and
consistent with current knowledge of the characteristics and extent of
production. The estimates include only those amounts considered to be Proved
Reserves and do not include additional amounts which may result from new
discoveries in the future, or from application of secondary and tertiary
recovery processes where facilities are not in place.
Proved Developed Reserves are reserves which can be expected to be recovered
through existing wells with existing equipment and operating methods. This
classification includes: a) proved developed producing reserves which are
reserves expected to be recovered through existing completion intervals now open
for production in existing wells; and b) proved developed nonproducing reserves
which are reserves that exist behind the casing of existing wells which are
expected to be produced in the predictable future, where the cost of making such
oil and gas available for production should be relatively small compared to the
cost of a new well.
Any reserves expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing primary recovery methods
are included as Proved Developed Reserves only after testing by a pilot project
or after the operation of an installed program has confirmed through production
response that increased recovery will be achieved.
Proved Undeveloped Reserves are Proved Reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage are limited to those drilling units offsetting productive units, which
are reasonably certain of production when drilled.
Proved Reserves for other undrilled units are claimed only where it can be
demonstrated with certainty that there is continuity of production from the
existing productive formation. No estimates for Proved Undeveloped Reserves are
attributable to or included in this table for any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated unless proved effective by actual tests in the area and in the same
reservoir.
The Company's engineering estimates indicate that a significant quantity of
natural gas reserves (net to the Company's interest) will be developed and
produced in association with the development and production of the Company's
proved oil reserves in Russia. The Company expects that, due to current market
conditions, it will initially reinject or flare such associated natural gas
production, and accordingly, no future net revenue has been assigned to these
reserves. Under the joint venture agreement, such reserves are owned by the
Company in the same proportion as all other hydrocarbons in the field, and
subsequent changes in conditions could result in the assignment of value to
these reserves.
Changes in previous estimates of proved reserves result from new information
obtained from production history and changes in economic factors.
S-27
<PAGE> 64
64
The evaluations of the oil and gas reserves as of December 31, 1998, 1997, 1996
and 1995 were audited by Huddleston & Co., Inc., independent petroleum
engineers.
<TABLE>
<CAPTION>
MINORITY
INTEREST IN
VENEZUELA RUSSIA TOTAL VENEZUELA NET TOTAL
--------- ------ ----- --------- ---------
<S> <C> <C> <C> <C> <C>
PROVED RESERVES-CRUDE OIL, CONDENSATE, AND GAS LIQUIDS
(MBBLS)
YEAR ENDED DECEMBER 31, 1998
Proved reserves beginning of the year 94,671 26,113 120,784 (18,934) 101,850
Revisions of previous estimates 25,119 (2,283) 22,836 (5,024) 17,812
Extensions, discoveries and improved recovery 30,217 8,147 38,364 (6,043) 32,321
Production (12,172) (924) (13,096) 2,434 (10,662)
------- ------ ------- ------- -------
Proved reserves end of year 137,835 31,053 168,888 (27,567) 141,321
======= ====== ======= ======= =======
YEAR ENDED DECEMBER 31, 1997
Proved reserves beginning of the year 86,076 23,544 109,620 (17,215) 92,405
Revisions of previous estimates 17,043 3,449 20,492 (3,409) 17,083
Extensions, discoveries and improved recovery 6,947 6,947 (1,389) 5,558
Production (15,395) (880) (16,275) 3,079 (13,196)
------- ------ ------- ------- -------
Proved reserves end of year 94,671 26,113 120,784 (18,934) 101,850
======= ====== ======= ======= =======
YEAR ENDED DECEMBER 31, 1996
Proved reserves beginning of the year 73,593 22,618 96,211 (14,718) 81,493
Revisions of previous estimates (10,951) 712 (10,239) 2,190 (8,049)
Extensions, discoveries and improved recovery 36,082 979 37,061 (7,216) 29,845
Production (12,648) (765) (13,413) 2,529 (10,884)
------- ------ ------- ------- -------
Proved reserves end of year 86,076 23,544 109,620 (17,215) 92,405
======= ====== ======= ======= =======
PROVED DEVELOPED RESERVES AT:
December 31, 1998 75,636 9,745 85,381 (15,127) 70,254
December 31, 1997 68,868 5,443 74,311 (13,774) 60,537
December 31, 1996 47,805 3,417 51,222 (9,561) 41,661
January 1, 1996 30,032 3,475 33,507 (6,006) 27,501
</TABLE>
The Company began 1996 with 6 Mmcf of proved developed natural gas reserves in
the United States. During 1996 the Company produced 1 Mmcf of the natural gas
and sold the remaining 5 Mmcf of natural gas reserves in place.
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO
PROVED OIL AND GAS RESERVE QUANTITIES
The standardized measure of discounted future net cash flows is presented in
accordance with the provisions of SFAS 69. In preparing this data, assumptions
and estimates have been used, and the Company cautions against viewing this
information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for
fixed and determinable escalations provided by contract, to the estimated future
production of year-end proved reserves. Future cash inflows were reduced by
estimated future production and development costs to determine pre-tax cash
inflows. Future income taxes were estimated by applying the year-end statutory
tax rates to the future pre-tax cash inflows, less the tax basis of the
properties involved, and adjusted for permanent differences and tax credits and
allowances. The resultant future net cash inflows are discounted using a ten
percent discount rate.
GEOILBENT received a waiver from the export tariff assessed on all oil produced
in and exported from Russia for 1995. In July 1996, such oil export tariffs were
terminated in conjunction with a loan agreement with the International Monetary
Fund, although new tariffs were introduced in 1999. Excise, pipeline and other
taxes continue to be levied on all oil producers and certain exporters. Although
the Russian regulatory environment has become less volatile, the Company is
unable to predict the impact of taxes, duties and other burdens for the future.
S-28
<PAGE> 65
65
<TABLE>
<CAPTION>
MINORITY
INTEREST IN
VENEZUELA RUSSIA TOTAL VENEZUELA NET TOTAL
--------- ------ ----- --------- ---------
(amounts in thousands)
<S> <C> <C> <C> <C> <C>
DECEMBER 31, 1998
Future cash inflow $ 778,765 $ 183,524 $ 962,289 $(155,753) $ 806,536
Future production costs (527,856) (70,953) (598,809) 105,571 (493,238)
Other related future costs (147,806) (25,048) (172,854) 29,561 (143,293)
---------- --------- ---------- --------- ----------
Future net revenue before income taxes 103,103 87,523 190,626 (20,621) 170,005
10% annual discount for estimated timing of cash flows (40,648) (37,977) (78,625) 8,130 (70,495)
---------- --------- ---------- --------- ----------
Discounted future net cash flows before income taxes 62,455 49,546 112,001 (12,491) 99,510
Future income taxes, discounted at 10% per annum - (6,298) (6,298) - (6,298)
---------- --------- ---------- --------- ----------
Standardized measure of discounted future net cash flows $ 62,455 $ 43,248 $ 105,703 $ (12,491) $ 93,212
========== ========= ========== ========= ==========
DECEMBER 31, 1997
Future cash inflow $ 923,421 $ 274,190 $1,197,611 $(184,684) $1,012,927
Future production costs (332,647) (74,326) (406,973) 66,529 (340,444)
Other related future costs (70,415) (53,283) (123,698) 14,083 (109,615)
---------- --------- ---------- --------- ----------
Future net revenue before income taxes 520,359 146,581 666,940 (104,072) 562,868
10% annual discount for estimated timing of cash flows (156,321) (68,885) (225,206) 31,264 (193,942)
---------- --------- ---------- --------- ----------
Discounted future net cash flows before income taxes 364,038 77,696 441,734 (72,808) 368,926
Future income taxes, discounted at 10% per annum (72,567) (14,263) (86,830) 14,513 (72,317)
---------- --------- ---------- --------- ----------
Standardized measure of discounted future net cash flows $291,471 $ 63,433 $354,904 $ (58,295) $ 296,609
========== ========= ========== ========= ==========
DECEMBER 31, 1996
Future cash inflow $1,036,611 $ 291,951 $1,328,562 $(207,322) $1,121,240
Future production costs (347,498) (94,279) (441,777) 69,500 (372,277)
Other related future costs (65,454) (45,723) (111,177) 13,091 (98,086)
---------- --------- ---------- --------- ----------
Future net revenue before income taxes 623,659 151,949 775,608 (124,731) 650,877
10% annual discount for estimated timing of cash flows (176,805) (61,244) (238,049) 35,361 (202,688)
---------- --------- ---------- --------- ----------
Discounted future net cash flows before income taxes 446,854 90,705 537,559 (89,370) 448,189
Future income taxes, discounted at 10% per annum (123,304) (17,282) (140,586) 24,661 (115,925)
---------- --------- ---------- --------- ----------
Standardized measure of discounted future net cash flows $323,550 $ 73,423 $396,973 $ (64,709) $ 332,264
========== ========= ========== ========= ==========
</TABLE>
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1998 1997 1996
---- ---- ----
(amounts in thousands)
<S> <C> <C> <C>
Balance, January 1 $ 354,904 $ 396,973 $ 261,995
Changes resulting from:
Sales of oil and gas, net of related costs (46,755) (122,179) (121,954)
Revisions to estimates of proved reserves
Pricing (411,986) (102,357) 108,705
Quantities 11,627 82,211 (56,315)
Sales of reserves in place - (18)
Extensions, discoveries and improved recovery,
net of future costs 46,748 25,725 183,968
Accretion of discount 44,174 53,756 37,230
Change in income taxes 80,532 53,756 (30,288)
Development costs incurred 55,601 61,207 63,013
Changes in timing and other (29,142) (94,188) (49,363)
--------- --------- ---------
Balance, December 31 $ 105,703 $ 354,904 $ 396,973
========= ========= =========
</TABLE>
S-29
<PAGE> 66
66
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of
Carpinteria, State of California, on the 30th day of March, 1999.
BENTON OIL AND GAS COMPANY
(Registrant)
Date: March 30, 1999 By: /s/A.E. Benton
-------------------- ---------------------------
A.E. Benton
Chief Executive Officer
and Principal Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed by the following persons on the 30th day of March, 1999,
on behalf of the Registrant in the capacities indicated:
<TABLE>
<CAPTION>
Signature Title
- --------- -----
<S> <C>
/s/A. E. Benton Chairman, Chief Executive Officer,
- ------------------------------------- President and Director
A. E. Benton
(Principal Executive Officer)
/s/James M. Whipkey Senior Vice President, Chief Financial
- ------------------------------------- Officer and Treasurer
James M. Whipkey
(Principal Financial Officer)
/s/Chris C. Hickok Vice President - Controller
- -------------------------------------
Chris C. Hickok
(Principal Accounting Officer)
/s/Michael B. Wray Vice Chairman and Director
- -------------------------------------
Michael B. Wray
/s/Bruce M. McIntyre Director
- -------------------------------------
Bruce M. McIntyre
/s/Richard W. Fetzner Director
- -------------------------------------
Richard W. Fetzner
/s/Garrett A. Garrettson Director
- -------------------------------------
Garrett A. Garrettson
</TABLE>
<PAGE> 67
67
EXHIBITS
<PAGE> 1
68
EXHIBIT 21.1
BENTON OIL AND GAS COMPANY
LIST OF SUBSIDIARIES
<TABLE>
<CAPTION>
JURISDICTION
NAME OF INCORPORATION
- --------------------------------------------------------- --------------------------
<S> <C>
Benton-Vinccler, C.A.* Venezuela
Energy International Financial Institution, Ltd.* Cayman Islands
Benton Offshore China Company Colorado
Benton Offshore China Holding Company Delaware
GEOILBENT, Ltd.* Russia
</TABLE>
The names of certain subsidiaries have been omitted in reliance upon Item
601(b)(21)(ii) of Regulation S-K.
*All subsidiaries are wholly-owned by Benton Oil and Gas Company, except
Benton-Vinccler, C.A. and Energy International Financial Institution which are
owned 80% by Benton Oil and Gas Company and GEOILBENT, Ltd. which is owned 34%
by Benton Oil and Gas Company.
<PAGE> 1
69
EXHIBIT 23.1
BENTON OIL AND GAS COMPANY
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-8 (Nos. 33-37124 and 333-19679) and in the Prospectuses
constituting part of the Registration Statements on Form S-3 (Nos. 33-70146,
33-79494, 333-00135 and 333-17231) and Form S-4 (Nos. 33-61299, 33-42139 and
333-06125) of Benton Oil and Gas Company of our report dated March 25, 1999
appearing on page S-1 of this Form 10-K.
PricewaterhouseCoopers LLP
San Francisco, California
March 30, 1999
<PAGE> 1
70
EXHIBIT 23.2
BENTON OIL AND GAS COMPANY
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-37124 and 333-19679 on Form S-8, 33-70146 on Form S-3, 333-00135 on Form S-3,
333-17231 on Form S-3, 33-79494 on Form S-3, 33-61299 on Form S-4, 33-42139 on
Form S-4 and 333-06125 on Form S-4 of Benton Oil and Gas Company of our report
dated March 24, 1998 appearing in this Annual Report on Form 10-K of Benton Oil
and Gas Company for the year ended December 31, 1998.
Deloitte & Touche LLP
Los Angeles, California
March 30, 1999
<PAGE> 1
71
EXHIBIT 23.3
BENTON OIL AND GAS COMPANY
INDEPENDENT PETROLEUM ENGINEERS' CONSENT
Huddleston & Co., Inc., hereby consents to the use of its name in reference to
it regarding its audit of the Benton Oil and Gas Company reserve reports, dated
as of December 31, 1998, in the Form 10-K Annual Report of Benton Oil and Gas
Company to be filed with the Securities and Exchange Commission.
Peter D. Huddleston, P.E.
Huddleston & Co., Inc.
Houston, Texas
March 24, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10K FOR
THE PERIOD ENDED DECEMBER 31, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<EXCHANGE-RATE> 1
<CASH> 18,147
<SECURITIES> 41,173
<RECEIVABLES> 17,307
<ALLOWANCES> 3,236
<INVENTORY> 0
<CURRENT-ASSETS> 92,809
<PP&E> 493,102
<DEPRECIATION> 339,636
<TOTAL-ASSETS> 338,621
<CURRENT-LIABILITIES> 36,945
<BONDS> 288,212
0
0
<COMMON> 296
<OTHER-SE> 12,693
<TOTAL-LIABILITY-AND-EQUITY> 338,621
<SALES> 90,271
<TOTAL-REVENUES> 112,148
<CGS> 80,313
<TOTAL-COSTS> 80,313
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 32,908
<INCOME-PRETAX> (230,695)
<INCOME-TAX> (24,220)
<INCOME-CONTINUING> (183,580)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (183,580)
<EPS-PRIMARY> (6.21)
<EPS-DILUTED> (6.21)
</TABLE>
