<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)
[X] of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 1997 or
Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from_______ to________
COMMISSION FILE NO.: 1-10762
----------------------------
BENTON OIL AND GAS COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
<TABLE>
<S> <C>
DELAWARE 77-0196707
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number)
1145 EUGENIA PLACE, SUITE 200
CARPINTERIA, CALIFORNIA 93013
(Address of principal executive offices) (Zip Code)
</TABLE>
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:
<TABLE>
<CAPTION>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ------------------- -----------------------------------------
<S> <C>
Common Stock, $.01 Par Value NYSE
Common Stock Purchase Warrants, $11.00 exercise price NASDAQ
</TABLE>
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
On March 25, 1998, the aggregate market value of the shares of voting stock of
Registrant held by non-affiliates was approximately $340,968,947 based on a
closing sales price on NYSE of $11.8125.
As of March 25, 1998, 29,521,396 shares of the Registrant's common stock were
outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 1998 Annual Meeting of
Stockholders to be filed with the Securities and Exchange Commission, not later
than 120 days after the close of its fiscal year, pursuant to Regulation 14A,
are incorporated by reference into Items, 10, 11, 12, and 13 of Part III of this
annual report.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.[X]
<PAGE> 2
<TABLE>
BENTON OIL AND GAS COMPANY
FORM 10-K
TABLE OF CONTENTS
Page
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Part I
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<S> <C> <C>
Item 1. Business.............................................................................3
Item 2. Properties..........................................................................20
Item 3. Legal Proceedings...................................................................20
Item 4. Submission of Matters to a Vote of Security Holders ................................21
Part II
- -------
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters........................................22
Item 6. Selected Consolidated Financial Data................................................23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................................25
Item 8. Financial Statements and Supplementary Data.........................................30
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ................................30
Part III
- --------
Item 10. Directors and Executive Officers of the Registrant .................................31
Item 11. Executive Compensation..............................................................31
Item 12. Security Ownership of Certain Beneficial
Owners and Management..................................................31
Item 13. Certain Relationships and Related Transactions .....................................31
Part IV
- -------
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K....................................................32
Financial Statements...............................................................................34
Signatures.........................................................................................59
</TABLE>
<PAGE> 3
PART I
The Company cautions that any forward-looking statements (as such term is
defined in the Private Securities Litigation Reform Act of 1995) contained in
this report or made by management of the Company involve risks and uncertainties
and are subject to change based on various important factors. The following
factors, among others, in some cases have affected and could cause actual
results and plans for future periods to differ materially from those expressed
or implied in any such forward-looking statements: fluctuations in oil and gas
prices, changes in operating costs, overall economic conditions, political
stability, currency and exchange risks, changes in existing or potential
tariffs, duties or quotas, availability of additional exploration and
development opportunities, availability of sufficient financing, changes in
weather conditions, and ability to hire and train personnel.
ITEM 1. BUSINESS
GENERAL
Benton Oil and Gas Company (the "Company") is an independent energy company
which has been engaged in the development and production of oil and gas
properties since 1989. The Company has developed significant interests in
Venezuela and Russia, and has recently acquired certain interests in China,
Jordan, Senegal and the United States. The Company's producing operations are
conducted principally through its 80%-owned Venezuelan subsidiary,
Benton-Vinccler, C.A. ("Benton-Vinccler"), which operates the South Monagas Unit
in Venezuela, and its 34%-owned Russian joint venture, GEOILBENT, which operates
the North Gubkinskoye Field in West Siberia, Russia. The Company has also
recently expanded into projects which involve exploration components, in
Venezuela through its participation in the Delta Centro exploration block, in
Santa Barbara County, California through the acquisition of a participation
interest in three state offshore oil and gas leases, and in China through a
farmout agreement with Shell Exploration (China) Limited ("Shell").
As of December 31, 1997, the Company had total assets of $584.3 million, total
estimated proved reserves of 120.8 MBOE, and a standardized measure of
discounted future net cash flow, before income taxes, for total proved reserves
of $441.7 million. For the year ended December 31, 1997, the Company had total
revenues of $179.0 million.
The Company has been successful in increasing reserves, production, and revenues
during the last four years. From year end 1993 through 1997, estimated proved
reserves increased from 42,785 MBOE to 120,784 MBOE and net annual production
increased from a total of 519 MBOE in 1993 to 16,275 MBOE in 1997. Earnings for
the year ended December 31, 1997 were $18.0 million compared to earnings for the
year ended December 31, 1996 of $28.3 million.
The Company was incorporated in Delaware in September 1988. Its principal
executive offices are located at 1145 Eugenia Place, Suite 200, Carpinteria,
California 93013, and its telephone number is (805) 566-5600.
BUSINESS STRATEGY
The Company's business strategy is to identify and exploit new oil and gas
reserves primarily in under-developed areas while seeking to minimize the
associated risk of such activities. Specifically, the Company endeavors to
minimize risk by employing the following strategies in its business activities:
(i) seek new reserves primarily in areas of low geologic risk; (ii) use proven
advanced technology in both exploration and development to maximize recovery,
including the exploration of higher risk, higher potential areas; (iii)
establish a local presence through joint venture partners and the use of local
personnel; (iv) commit capital in a phased manner to limit total commitments at
any one time; and (v) reduce foreign exchange risks through receipt of revenues
in U.S. currency.
SEEK NEW RESERVES IN AREAS OF LOW GEOLOGIC RISK. The Company has had significant
success in identifying under-developed reserves in the U.S. and internationally.
In particular, the Company has notable experience and expertise in seeking and
developing new reserves in countries where perceived potential political and
operating difficulties have sometimes discouraged other energy companies from
competing. As a result, the Company has established operations in Venezuela and
Russia, which have significant reserves that have been acquired and are being
developed at relatively low costs.
<PAGE> 4
USE OF PROVEN ADVANCED TECHNOLOGY IN BOTH EXPLORATION AND DEVELOPMENT. The
Company's use of 3-D seismic technology, in which a three dimensional image of
the earth's subsurface is created through the computer interpretation of seismic
data, combined with its experience in designing the seismic surveys and
interpreting and analyzing the resulting data, allow for a more detailed
understanding of the subsurface than do conventional surveys. Such technology
contributes significantly to field appraisal, development and production. The
3-D seismic information, in conjunction with subsurface geologic data from
previously drilled wells, is used by the Company's experienced in-house
technical team to identify previously undetected reserves. The 3-D seismic
information can also be used to guide drilling on a real-time basis, and has
been especially helpful in the horizontal drilling done in Venezuela in order to
take advantage of oil-trapping faults. The Company has recently acquired rights
to establish operations in the United States, China, Jordan and Senegal and is
seeking similar opportunities to explore higher risk, higher potential prospects
in other regions and areas.
ESTABLISH A LOCAL PRESENCE THROUGH JOINT VENTURE PARTNERS AND THE USE OF LOCAL
PERSONNEL. The Company has sought to establish a local presence where it does
business to facilitate stronger relationships with the local governments and
labor organizations through joint venture arrangements with local partners.
Moreover, the Company employs almost exclusively local personnel to run foreign
operations both to take advantage of local knowledge and experience and to
minimize cost. These efforts have created an expertise within Company management
in forming effective foreign partnerships and operating abroad. The Company
believes that it has gained access to new development opportunities as a result
of its reputation as a dependable partner.
COMMIT CAPITAL IN A PHASED MANNER TO LIMIT TOTAL COMMITMENTS AT ANY ONE TIME.
While the Company typically has agreed to a minimum capital expenditure or
development commitment at the outset of new projects, expenditures to fulfill
these commitments are phased over time. In addition, the Company seeks, where
possible, to use internally generated funds for further capital expenditures and
to invest in projects which provide the potential for an early return to the
Company.
REDUCE FOREIGN EXCHANGE RISKS. The Company seeks to reduce foreign currency
exchange risks by providing for the receipt of revenues by the Company in U.S.
dollars while most operating costs are incurred in local currency. Pursuant to
the operating agreement between Benton-Vinccler and Lagoven, S. A., then one of
three exploration and production affiliates of the national oil company
Petroleos de Venezuela, S.A. ("PDVSA") which have subsequently all been combined
into PDVSA Petroleo y Gas, S.A. ("P&G"), the operating fees earned by the
Company are paid directly to the Company's bank account in the United States in
U.S. dollars. GEOILBENT receives revenues from export sales in U.S. dollars paid
to its account in Moscow. As the Company continues to expand internationally, it
will seek to establish similar arrangements for new operations.
PRINCIPAL AREAS OF ACTIVITY
The following table summarizes the Company's proved reserves, drilling and
production activity, and financial operating data by principal geographic area
at and for each of the years ended December 31:
<TABLE>
<CAPTION>
VENEZUELA (1) RUSSIA (2)
-------------------------------- --------------------------------
(dollars in 000's) 1997 1996 1995 1997 1996 1995
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
RESERVE INFORMATION:
Proved Reserves (MBOE) 94,671 86,076 73,593 26,113 23,544 22,618
Discounted Future Net Cash
Flow Attributable to
Proved Reserves,
Before Income Taxes $364,038 $446,854 $286,916 $ 77,696 $ 90,705 $ 85,361
Standardized Measure of Future
Net Cash Flows $291,471 $323,550 $206,545 $ 63,433 $ 73,423 $ 55,434
DRILLING AND PRODUCTION ACTIVITY:
Gross Wells Drilled 27 33 19 7 5 25
Average Daily Production (BOE) 42,178 34,557 14,949 2,411 2,091 1,345
</TABLE>
<PAGE> 5
<TABLE>
<CAPTION>
VENEZUELA (1) RUSSIA (2)
-------------------------------- --------------------------------
<S> <C> <C> <C> <C> <C> <C>
(dollars in 000's) 1997 1996 1995 1997 1996 1995
-------- -------- -------- -------- -------- --------
FINANCIAL DATA:
Oil and Gas Revenues $154,119 $136,840 $ 49,174 $ 9,925 $ 9,047 $ 6,016
Expenses:
Lease Operating Costs and
Production Taxes 34,516 17,669 6,483 7,349 6,605 2,764
Depletion 43,584 29,523 11,393 3,079 2,747 1,512
-------- -------- -------- -------- -------- --------
Total Expenses 78,100 47,192 17,876 10,428 9,352 4,276
-------- -------- -------- -------- -------- --------
Results of Operations from
Oil and Gas Producing
Activities $ 76,019 $ 89,648 $ 31,298 $ (503) $ (305) $ 1,740
======== ======== ======== ======== ======== ========
<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 P&G under which all mineral rights are owned by the Government of Venezuela. See
"--South Monagas Unit, Venezuela."
(2) The financial information for Russia includes the Company's 34% share of the information for the nine months
ended September 30, 1995 and the twelve months ended September 30, 1996 and 1997, the end of the fiscal period
for GEOILBENT. See Note 18 to the Company's Consolidated Financial Statements.
</FN>
</TABLE>
SOUTH MONAGAS UNIT, VENEZUELA
GENERAL
In July 1992, the Company and Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), a Venezuelan construction and engineering company,
signed a 20-year operating service agreement with P&G to reactivate and further
develop the Uracoa, Tucupita and Bombal Fields, which are a part of the South
Monagas Unit (the "Unit"). At that time, the Company was one of three foreign
companies ultimately awarded an operating service agreement to reactivate
existing fields by PDVSA, and was the first U.S. company since 1976 to be
granted such an oil field development contract in Venezuela.
The oil and gas operations in the Unit are conducted by Benton-Vinccler, the
Company's 80%-owned subsidiary. The remaining 20% of the outstanding capital
stock of Benton-Vinccler is owned by Vinccler. The Company, through its majority
ownership of stock in Benton-Vinccler, makes all operational and corporate
decisions related to Benton-Vinccler, subject to certain super-majority
provisions of Benton-Vinccler's charter documents related to mergers,
consolidations, sales of substantially all of its corporate assets, change of
business and similar major corporate events. Vinccler has an extensive operating
history in Venezuela. It provided the Company with initial financial assistance
and continues to provide ongoing assistance with construction services and
governmental and labor relations.
Under the terms of the operating service agreement, Benton-Vinccler is a
contractor for P&G and is responsible for overall operations of the Unit,
including all necessary investments to reactivate and develop the fields
comprising the Unit. The Venezuelan government maintains full ownership of all
hydrocarbons in the fields. In addition, P&G maintains full ownership of
equipment and capital infrastructure following its installation. Benton-Vinccler
invoices P&G each quarter based on Bbls of oil accepted by P&G during the
quarter, using quarterly adjusted contract service fees per Bbl, and receives
its payments from P&G in U.S. dollars deposited directly into a U.S. bank
account. The operating service agreement provides for Benton-Vinccler to receive
an operating fee for each Bbl of crude oil delivered and a capital recovery fee
for certain of its capital expenditures, provided that such operating fee and
capital recovery fee cannot exceed the maximum total fee per Bbl set forth in
the agreement. The operating fee is subject to periodic adjustments to reflect
changes in the special energy index of the U.S. Consumer Price Index, and the
maximum total fee is subject to periodic adjustments to reflect changes in the
average of certain world crude oil prices. Since commencement of operations, the
Company has received approximately $10.2 million in capital recovery fees. The
Company cannot predict the extent to which future maximum total fee adjustments
will provide for capital recovery components in the fees it receives, and has
recorded no asset for future capital recovery fees.
<PAGE> 6
LOCATION AND GEOLOGY
The Unit extends across the southeastern part of the state of Monagas and the
southwestern part of the state of Delta Amacuro in eastern Venezuela. The Unit
is approximately 51 miles long and eight miles wide and consists of 157,843
acres, of which the fields comprise approximately one-half. At December 31,
1997, proved reserves attributable to the Company's Venezuelan operations were
94,671 MBOE, which represented approximately 78% of the Company's proved
reserves. Benton-Vinccler is currently developing the Oficina sands in the
Uracoa Field, which contain 75% of the Unit's proved reserves and has begun the
development of the Tucupita and Bombal fields which contain the remaining 25% of
the Unit's reserves. The associated natural gas produced at Uracoa is currently
being reinjected into the field, as no ready market exists for the natural gas.
DRILLING AND DEVELOPMENT ACTIVITY
Uracoa Field
- ------------
Benton-Vinccler has been developing the South Monagas Unit since 1992. During
March 1998 (through March 25), a total of approximately 84 wells were producing
an average of approximately 39,400 Bbls of oil per day in the Uracoa Field. The
following table sets forth the Uracoa Field drilling activity and production
information for each of the quarters presented:
<TABLE>
<CAPTION>
WELLS DRILLED
---------------------------- AVERAGE DAILY
VERTICAL HORIZONTAL PRODUCTION FROM FIELD (BBL)
-------- ---------- ---------------------------
<S> <C> <C> <C>
1995:
First Quarter 1 1 11,800
Second Quarter 1 2 11,300
Third Quarter 3 2 15,800
Fourth Quarter 1 8 20,800
1996:
First Quarter 1 8 29,600
Second Quarter 5 4 33,700
Third Quarter 2 7 37,700
Fourth Quarter 1 4 37,500
1997:
First Quarter 2 6 36,100
Second Quarter 4 4 35,800
Third Quarter 1 6 40,500
Fourth Quarter 1 2 44,400
</TABLE>
Benton-Vinccler contracts with third parties for drilling and completion of
wells. Currently, Helmerich & Payne International Drilling Co. is performing
drilling services for Benton-Vinccler. The Company's technical personnel
identify drilling locations, specify the drilling program and equipment to be
used and monitor the drilling activities. To date, 15 previously drilled wells
have been reactivated, 88 new wells have been drilled in the Uracoa Field using
modern drilling and completion techniques that had not previously been utilized
on the field, with 88 wells, or 100%, completed and placed on production, and
eight injection wells have been drilled and two other wells converted to
injectors.
In December 1993, Benton-Vinccler commenced drilling the first horizontal well
in the Uracoa Field. Since the completion of this well, the Company has
successfully integrated modern technology and modern drilling and completion
techniques to improve the ultimate recovery. The Company has conducted a 3-D
seismic survey and interpreted the seismic data over the Uracoa Field. As a
horizontal well is drilled, information regarding formations encountered by the
drill bit is transmitted to the Company. Geologists, engineers and geophysicists
at the Company can determine the location of the drill bit by comparing the
information about the formations being drilled with the 3-D seismic data. The
Company then directs the movement of the drill bit to more accurately direct the
well to the expected reservoir. The Company intends to continue this method of
horizontal drilling in the development of the field with an estimated capital
expenditure of $24.0 million in 1998.
<PAGE> 7
Oil produced in the Uracoa Field is transported to production facilities which
were designed in the United States and installed by Benton-Vinccler. These
production facilities are of the type commonly used in heavy oil production in
the United States, but not previously used extensively in Venezuela to process
crude oil of similar gravity or quality. The current production facilities have
the capacity to process 60 MBbls of oil per day.
Tucupita and Bombal Fields
- --------------------------
Before becoming inactive in 1987, the Tucupita Field had been substantially
developed, producing 67.1 MMBbls of oil, 34.7 MMBbls of water and 17.6 Bcf of
natural gas. Benton-Vinccler drilled a successful pilot well in late 1996 to
evaluate the remaining development potential of the Tucupita Field. This well
has produced at an approximate average rate of 2,500 Bbls of oil per day and
9,900 Bbls of water per day through December 1997.
The Company's approach to the future development of the Tucupita Field is to
process large volumes of fluid to access the remaining oil. Working under the
assumption that this field was abandoned prematurely, the Company will use new
technology, including large diameter wellbores and high volume pumps, to produce
the reservoir at progressively higher water to oil ratios. Based on the
performance of this pilot well, as well as the Company's analysis of
high-quality 3-D seismic surveys, a significant redevelopment effort is now
underway. A combination of horizontal, deviated and vertical wells will be
drilled to exploit the remaining oil reserves.
Beginning in early 1998, Benton-Vinccler will drill nine producing wells and two
water injection wells, and will expand production facilities, at an estimated
aggregate cost of $40.0 million. Currently, oil is being trucked from the
Tucupita Field to the Uracoa processing facilities. Benton-Vinccler is analyzing
alternatives for barging the oil and for installing a pipeline from the Tucupita
Field to the Uracoa Field.
The prospective pipeline would also be used for production from the Bombal Field
when it is developed. To date, the Company has drilled one well in the Bombal
Field and reactivated another, resulting in current combined production of 800
Bbls of oil per day. Benton-Vinccler currently plans to further develop the
Bombal Field beginning in late 1998 by drilling an additional evaluation well,
at an anticipated cost of up to $2.6 million.
CUSTOMERS AND MARKET INFORMATION
Oil produced in Venezuela is delivered to P&G under the terms of an operating
service agreement for an operating service fee. Benton-Vinccler has constructed
a 25-mile oil pipeline from its oil processing facilities at Uracoa to P&G's
storage facility, which is the custody transfer point. The service agreement
specifies that the oil stream may contain no more than 1% base sediment and
water, and quality measurements are conducted both at Benton-Vinccler's
facilities and at P&G's storage facility. A continuous flow measuring unit is
installed at Benton-Vinccler's facility, so that quantity is monitored
constantly. P&G provides Benton-Vinccler with a daily acknowledgment regarding
the amount of oil accepted the previous day, which is reconciled to
Benton-Vinccler's measurement. At the end of each quarter, Benton-Vinccler
prepares an invoice to P&G for that quarter's deliveries. P&G pays the invoice
at the end of the second month after the end of the quarter. Invoice amounts and
payments are denominated in U.S. dollars. Payments are wire transferred into
Benton-Vinccler's account in New York.
EMPLOYEES; COMMUNITY RELATIONS
Benton-Vinccler seeks to employ nationals rather than bring expatriates into the
country. Presently, there are 12 full-time expatriates working with
Benton-Vinccler and 175 local employees. Benton-Vinccler also conducts ongoing
community relations programs, providing medical care, training, equipment and
supplies, and support for local schools, in both states in which the Unit falls.
<PAGE> 8
DELTA CENTRO BLOCK, VENEZUELA
GENERAL
In January 1996, the Company and its bidding partners, Louisiana Land and
Exploration ("LL&E"), which was recently acquired by Burlington Resources Inc.,
and Norcen Energy Company ("Norcen"), recently acquired by Union Pacific
Resources Group Inc., were awarded the right to explore and develop the Delta
Centro Block in Venezuela. The contract requires a minimum exploration work
program consisting of completing a 550 square kilometer 3-D and a 289 kilometer
2-D seismic survey and drilling three wells to depths of 12,000 to 18,000 feet
within five years. PDVSA estimates that this minimum exploration work program
will cost $60.0 million, and required that the Company, LL&E and Norcen each
post a performance surety bond or standby letter of credit for its pro rata
share of the estimated work commitment expenditures. The Company has provided a
standby letter of credit in the amount of $18.0 million. The Company has a 30%
interest in the exploration venture, with LL&E and Norcen each owning a 35%
interest. Under the terms of the operating agreement, which establishes the
management company for the project, LL&E is the operator of the block and
therefore the Company does not exercise control of the operations of the
venture. It is currently anticipated that Corporacion Venezolana del Petroleo,
S.A. ("CVP"), an affiliate of PDVSA, will have a 35% interest in the management
company, which will dilute the voting power of the partners on a pro rata basis.
If areas within the block are deemed to be commercially viable, then the group
has the right to enter into further agreements with CVP to develop those areas
during the next 20-25 years. CVP would participate in the revenues and costs
with an interest between 1 and 35%, at CVP's discretion. Any oil and gas
produced by the Delta Centro consortium will be sold at market prices and will
be subject to the oil and gas taxation regime in Venezuela and to the terms of a
profit sharing agreement with PDVSA. Under the current oil and gas tax law, a
royalty of up to 16.66% will be paid to the state. Under the contract bid terms,
41% of the pre-tax income will be shared with PDVSA for the period during which
the first $1.0 billion of revenues is produced; thereafter, the profit sharing
amount may increase to up to 50% according to a formula based on return on
assets. Currently, the statutory income tax rate for oil and gas enterprises is
67.7%. Royalties and shared profits are currently deductible for tax purposes.
LOCATION AND GEOLOGY
The Delta Centro block consists of approximately 2,100 square kilometers
(526,000 acres) located in the delta of the Orinoco River in the eastern part of
Venezuela. Although no significant exploratory activity has been conducted on
the block, PdVSA has estimated that the area may contain recoverable reserves of
as much as 820 MMBbls, and may be capable of producing up to 160 MBbls of oil
per day. The general area of Venezuela in which the Delta Centro Block is
located is known to be a significant source of hydrocarbons, evidenced by the
Orinoco tar sands to the south and the El Furrial light oil trend to the
northwest. Based on its geological studies of the basins in this area, the
Company's technical staff believes that hydrocarbons have essentially migrated
over time from the deeper Maturin basin area of Venezuela southward toward the
shallower Orinoco tar belt area. If so, then potential trapping structures
and/or faults in the path of the migrating oil would serve as traps for the
migrating oil and have the opportunity to be filled to their spill points. Delta
Centro is directly in line with this migration path, making it an attractive
exploration area. The area is mostly swampy in nature, with terrain ranging from
forest in the north to savannah in the south. The marshlands in the block are
similar to the transition zone areas in the Gulf of Mexico in which the Company
has significant experience in seismic and drilling operations.
DRILLING AND DEVELOPMENT ACTIVITY
The venture has acquired a 598 square kilometer 3-D seismic survey over the
southwestern portion of the Delta Centro Block and a 371 kilometer 2-D seismic
survey to evaluate the remaining exploration potential of the block, at an
expected total cost to the Company of approximately $8.0 million, of which $4.0
million had been spent through December 31, 1997. Following the initial
interpretation of the seismic data, the venture intends to drill an initial
exploration well during the fourth quarter of 1998, at a cost to the Company of
approximately $4.3 million.
COMMUNITY AND COUNTRY RELATIONS
The Company conducts an ongoing community relations program in the area,
providing medical care, equipment and supplies to the Waroa tribe which resides
in this area.
<PAGE> 9
NORTH GUBKINSKOYE, RUSSIA
GENERAL
In December 1991, the joint venture agreement forming GEOILBENT among the
Company (34% interest) and two Russian partners, Purneftegasgeologia and
Purneftegas (each having a 33% interest), was registered with the Ministry of
Finance of the USSR. In November 1993, the agreement was registered with the
Russian Agency for International Cooperation and Development. Although GEOILBENT
may only take action through the unanimous vote of the partners, the Company
believes that it has developed a good relationship with its partners and has not
experienced any disagreement with its partners on major operational matters. Mr.
A.E. Benton, Chief Executive Officer of the Company, serves as Chairman of the
Board of GEOILBENT.
LOCATION AND GEOLOGY
GEOILBENT develops, produces and markets crude oil from the North Gubkinskoye
and the Prisklonovoye Fields in the West Siberia region of Russia, located
approximately 2,000 miles northeast of Moscow. The field, which covers an area
approximately 15 miles long and 4 miles wide, has been delineated with over 60
exploratory wells (which tested 26 separate reservoirs) and is surrounded by
large proven fields. Before commencement of GEOILBENT's operations, the North
Gubkinskoye Field was one of the largest oil and gas fields in the region not
under commercial production. The field is a large anticlinal structure with
multiple pay sands. The development to date has focused on the BP 8, 9, 10, 11
and 12 reservoirs with only minor development in the BP 7 reservoir. The
produced natural gas is currently being flared in accordance with environmental
regulations.
DRILLING AND DEVELOPMENT ACTIVITY
GEOILBENT commenced initial operations in the field during the third quarter of
1992 with the construction of a 37-mile oil pipeline and installation of
temporary production facilities. During March 1998 (through March 25),
approximately 43 wells were producing an average of approximately 8.3 MBbls of
oil per day. The following table sets forth drilling activity and production
information for each of the quarters presented:
<TABLE>
<CAPTION>
AVERAGE DAILY
WELLS DRILLED PRODUCTION FROM FIELD
------------- ---------------------
<S> <C> <C>
1995:
First Quarter 4 4,300
Second Quarter 1 5,600
Third Quarter 9 7,800
Fourth Quarter 11 7,900
1996:
First Quarter 4 8,400
Second Quarter 1 7,200
Third Quarter - 7,100
Fourth Quarter - 6,500
1997:
First Quarter 1 6,300
Second Quarter 2 6,800
Third Quarter 1 6,800
Fourth Quarter 3 6,600
</TABLE>
GEOILBENT contracts with third parties for drilling and completion of wells.
Supervised by a joint American and Russian management team, GEOILBENT identifies
drilling locations, then uses Russian drilling rigs, upgraded by certain western
technology and materials including shaker screens, monitoring equipment and
drilling and completion fluids, to drill and complete a well. To date, 14
previously drilled wells have been reactivated and 56 wells have been drilled in
the field, with 46 wells, or 82%, completed and placed on production. Five
drilling rigs are currently working on
<PAGE> 10
pads in the field, and once all wells on the pad have been drilled, each such
well will be tested for completion. Each well is drilled to an average depth of
approximately 9,000 feet measured depth and 8,000 feet true vertical depth.
Oil produced from the North Gubkinskoye Field is transported to production
facilities constructed and owned by GEOILBENT. Oil is then transferred to
GEOILBENT's 37-mile pipeline which transports the oil from the North Gubkinskoye
Field south to the main Russian oil pipeline network.
The current production facilities are operating at or near capacity and will
need to be expanded to accommodate production increases. GEOILBENT has obtained
financing through a $65 million parallel loan facility (the "EBRD Credit
Facility") for the development of the North Gubkinskoye Field from the European
Bank for Reconstruction and Development (the "EBRD") and International Moscow
Bank ("IMB"). GEOILBENT has a 1998 capital expenditure budget of approximately
$65.0 million, of which $49.0 million would be used to drill approximately 60
wells in the North Gubkinskoye Field and $16.0 million for construction of
production facilities. The initial tranche of $12.0 million has been advanced
from the EBRD Credit Facility and additional borrowing will be based on
achieving certain reserve and production milestones. Additional expenditures in
excess of $12.0 million will be dependent upon increased availability to draw
from the EBRD Credit Facility and cash flow from operations.
CUSTOMERS AND MARKET INFORMATION
GEOILBENT's 37-mile pipeline runs from the field to the main pipeline in the
area where GEOILBENT transfers the oil to Transneft, the state oil pipeline
monopoly. Transneft then transports the oil to the western border of Russia. All
export oil sales are handled by trading companies such as Russoil or NAFTA
Moscow. All export sales have been paid in U.S. dollars into GEOILBENT's account
in Moscow.
EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS
Having access to the oilfield labor base in West Siberia, GEOILBENT employs
Russian nationals almost exclusively. Presently, there are four full-time
expatriates working with GEOILBENT and 230 local employees. The Company conducts
an ongoing community relations program in Russia, providing medical care,
training, equipment and supplies in towns in which GEOILBENT personnel reside
and also for the nomadic indigenous population which resides in the area of
oilfield operations.
ALTERNATIVES FOR NATURAL GAS RESERVES
The Company and GEOILBENT estimate that substantial recoverable associated gas
reserves exist in the North Gubkinskoye Field. In addition, there are
substantial non-associated natural gas reserves in the field. While associated
gas is currently flared in allowable amounts under permits with the Ministry of
Fuel and Energy, the Company is moving forward with plans to sell such gas in
the local marketplace. Discussions are underway with Gazprom, the state natural
gas monopoly, for development, production and sales of both associated and
non-associated gas, which together are estimated by the Company to approximate
3.5 Tcf. First stage development of the North Gubkinskoye gas reserves would
likely involve construction of a natural gas pipeline from the field to the
local gas processing plant, as well as possible expansion of that plant.
Preliminary analysis indicates that the Company's 1998 capital investment in
such projects could be about $10.0 million.
WAB-21, SOUTH CHINA SEA
GENERAL
In December 1996, the Company acquired Crestone Energy Corporation ("Crestone"),
a privately held company headquartered in Denver, Colorado. Crestone's principal
asset is a petroleum contract with China National Offshore Oil Company ("CNOOC")
for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in
the South China Sea, with an option for an additional 1.0 million acres under
certain circumstances.
<PAGE> 11
LOCATION AND GEOLOGY
The WAB-21 Contract Area (the "Contract Area") is located approximately 50 miles
east of the Dai Hung (Big Bear) Oil Field. The Contract Area covers several
similar structural trends each with potential for large hydrocarbon reserves in
possible multiple pay zones.
The Contract Area is located northwest of Zengmu Basin (Offshore Sarawak), where
two Chinese institutions have already conducted geophysical seismic surveys.
Based on the multi-disciplinary data available from Zengmu Basin to the
southeast, East Natuna Basin to the south and southwest, and WAN'AN (Con Son)
Basin to the west and northwest there is substantial evidence of significant
hydrocarbon potential in the Contract Area. Geophysical data indicates the
possibility of several geologic horizons with complete assemblages of source
rocks, reservoir rocks and cap rocks.
POLITICAL CONSIDERATIONS AND RISKS
China's claim of ownership of the area results from China's discovery and
China's use and historic administration of the area. This claim also includes
third party and official foreign government recognition of China's sovereignty
and jurisdiction over the Contract Area.
The nearby Nansha Islands were formally placed under Chinese administration
during the Ming Dynasty (1368-1644 AD). In 1883, Germans were banned from
geologically surveying the area by the Quing court, based on Chinese sovereignty
over the region. Since the establishment of Chinese government jurisdiction over
the area several hundred years ago, the Nansha Islands have long been recognized
as being Chinese territory. Additionally, Russian and Vietnamese maps have
historically shown this area as Chinese. Significantly, even Vietnam recognized
China's sovereignty of the islands from 1956 until 1975. Vietnam's former
Premier Van Dong acknowledged China's Nansha Island sovereignty in a diplomatic
note in 1958.
In April 1994, a Chinese seismic survey ship contracted by the Company's
predecessor was intercepted by Vietnamese boats in the Contract Area while
attempting to conduct seismic acquisition operations. The Chinese ship returned
to its port without commencing its seismic work program. China subsequently
denounced Vietnam's action.
Since 1994 China has maintained publicly that it is willing to discuss the joint
development of the Contract Area with the Vietnamese government. Thus far
Vietnam has not responded favorably. Instead, Vietnam granted exploration and
development rights to parts of the Contract Area to Conoco, a division of DuPont
Corporation. Diplomatic efforts have been conducted to resolve the territorial
dispute but have thus far been unsuccessful and any exploration activities will
be subject to resolution of such dispute. The Company has recorded no reserves
attributable to this petroleum contract.
DRILLING AND DEVELOPMENT ACTIVITY
The Company has submitted, and received approval of, an initial seismic program
covering a portion of the Contract Area which anticipates capital expenditures
by the Company of approximately $8.0 million during the first year of activity.
However, until such time as the territorial dispute has been resolved, the
Company does not anticipate making significant capital expenditures for
exploration or development of the Contract Area.
QINGSHUI BLOCK, CHINA
GENERAL
In October 1997, the Company signed a farmout agreement with Shell pursuant to
which the Company will acquire a 50% participation interest in Shell's Liaohe
area onshore exploration project in northeast China. Shell has entered into a
petroleum contract with the China National Petroleum Corporation ("CNPC") to
explore and develop the deep rights in the Qingshui Block, a 563 square
kilometer area (approximately 140,000 acres) in the delta of the Liaohe River.
The deep rights are below 3,300 and 3,500 meters. The contract requires a
three-phase exploration program. Shell will be the operator of the project.
<PAGE> 12
Pursuant to the petroleum contract, the first exploration period commenced
November 1, 1996. In September 1997, Shell notified CNPC of its intention to
continue with the first exploration phase. Pursuant to the terms of the
contract, this nine month study phase required a work commitment to evaluate the
deep potential of the block, with an expected minimum expenditure of $3.0
million dollars. During the remainder of the first exploration phase and prior
to November 1, 1999, Shell is required to drill and complete one exploratory
well to a depth of 4,500 meters, with a minimum expenditure of $8.0 million
dollars. The second exploration phase must be completed within two years of
commencement of that phase. Phase two requires Shell to drill and complete one
Exploratory Well to 4,500 meters with a minimum expenditure of $8.0 million
dollars. At the commencement of phase two, 10% of the phase one contract area
must be relinquished. The third exploration phase must be completed within two
years of commencement of such phase. Shell is required to drill and complete one
additional exploratory well to 4,500 meters with a minimum expenditure of $8.0
million dollars. At the commencement of the third exploration phase, 30% of the
phase two contract area must be relinquished. At the conclusion of each of the
exploration phases, Shell will elect whether or not to continue to the next
exploration phase. Assuming that Shell and the Company have performed each of
the three phases, the Company's maximum aggregate capital commitment will be
$22.0 million. Following the exploration phase under the contract, the contract
permits production from each oil field identified in the exploration phase for a
period of 15 years. CNPC has the right to retain up to a 51% interest in the
block and will pay none of the costs of the initial three Exploratory Wells.
CNPC will thereafter pay its proportionate share of all development and
operating costs in the block and will receive its proportionate share of all
production from the block, including production from the initial three wells.
Shell and the Company will therefore receive at least an aggregate 49% interest
in the production from the block and will pay its proportionate share of all
development and operating costs.
Pursuant to the farmout agreement between Shell and the Company, the Company
will have 50% of Shell's working interest in the block. The Company is required
to pay to Shell 50% of Shell's costs to date, estimated to be approximately $4.0
million, representing a cost to the Company of $2.0 million. In addition, the
Company agrees to pay 100% of the first $8.0 million of the costs for the phase
one exploration period, after which, costs will be shared equally. If the first
phase of the exploration period results in a commercial discovery, the Company
agrees to pay 100% of the first $8.0 million of the costs for the second phase
of the exploration period, after which, costs will be shared equally. The
Company and Shell will share costs equally for the third exploration phase.
LOCATION AND GEOLOGY
The petroleum contract covers the deep rights in the Qingshui Block, a 563
square kilometer area located onshore in northeast China, in the delta area of
the Liaohe River, Liaoning Province. The acreage is situated in a structurally
complex half-graben basin, associated with a deep-seated wrench zone. The
graben-fill consists of sediments containing oil prone source rocks, turbiditic
to lacustrine deltaic reservoir sequences and lacustrine mudstone cap rocks.
Shell's evaluation of the block is based on comprehensive data enhancement and
analysis, including core evaluation, petrophysics and 2-D seismic reprocessing,
3-D seismic mapping and volume interpretation, charge modeling and dynamic
reservoir simulations.
DRILLING AND DEVELOPMENT ACTIVITY
The Company expects to drill one exploration well in the block beginning in the
fourth quarter of 1998 with an anticipated capital expenditure to the Company of
approximately $10.0 million.
SANTA BARBARA COUNTY, CALIFORNIA
GENERAL
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy. The project
area covers the Molino, the Gaviota and the Caliente fields, located
approximately 35 miles west of Santa Barbara, California. Molino Energy holds a
100% working interest in each of the leases. The Company serves as operator of
the project. In consideration of the 40% participation interest, the Company
will initially pay 100% of the costs of the first well to be drilled on the
block, which began in March 1998. The Company's cost participation in the first
well will be reduced to 53% when an amount equal to 70% of costs of $2.5
million incurred by Molino Energy prior to the agreement with the Company is
paid from 47% of the Company's initial cost participation. The Company will then
pay 40% of all subsequent costs.
<PAGE> 13
LOCATION AND GEOLOGY
The Company's operating interest covers three known fields, located on three
adjacent state oil and gas leases off the central California coast. Each of
these leases covers approximately 4,000 acres. The Molino, Gaviota and Caliente
Fields have produced an aggregate of 363 Bcf of natural gas from subsea
completion in the Vaqueras formation, and the deeper, Sacate/Matilija formation
has produced 12 Bcf of natural gas from the Molino field. In addition, the
Monterey formation has been penetrated from all of the gas wells, but has never
been produced. The Monterey formation is known as a prolific oil producer in
this area.
DRILLING AND DEVELOPMENT ACTIVITY
In March 1998, the Company began drilling the first well in the project on Lease
No. 2199 on the Gaviota structure from an onshore drillsite. The onshore drill
site has immediate access to oil and gas pipelines. The well is planned to have
a measured depth of 14,800 total feet, with a true vertical depth of 10,700 feet
and a maximum horizontal displacement of about 6,800 feet. The well will target
the Oligocene age Vacqueros and Eocene age Sacate/Matilija formations, which are
known gas/condensate reservoirs in other nearby fields. The Company anticipates
that the first well will cost approximately $4.0 million.
SIRHAN BLOCK, JORDAN
GENERAL
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with the Natural Resources Authority of Jordan
("NRA"), established by the Hashemite Kingdom of Jordan, to explore, develop,
and produce the Sirhan block in southeastern Jordan.
Under the terms of the PSA, the Company is obligated to make certain capital and
operating expenditures in a first phase and may elect to continue into
additional phases with minimum commitments as follows: $5.1 million in the first
exploration phase (2 years) to perform geological studies and expenses incurred
in drilling Exploratory Wells; $8.0 million in the second exploration phase (3
years) for seismic acquisitions, geological studies, and expenses incurred in
drilling Exploratory Wells; and $10.0 million in the third exploration phase (3
years) for seismic acquisitions, geological studies, and expenses incurred in
drilling Exploratory Wells. If the Company expends more than the minimum
expenditure in one phase, the excess expenditure will be credited against the
Company's minimum expenditure obligation during the next phase. In addition, the
Company will be entitled to recover all operating costs and expenses incurred.
LOCATION AND GEOLOGY
The Sirhan block in southeastern Jordan consists of approximately 1.2 million
acres (4,827 square kilometers). This block is located in the Sirhan basin
adjacent to the Jordan-Saudi Arabia border. One existing well on the block
tested light oil at low rates and several additional wells encountered thick
zones with indications of gas that have not been tested.
DRILLING AND DEVELOPMENT ACTIVITY
During the first quarter of 1998, the Company reentered two wells and tested two
different reservoirs. The WS-10 well was tested in the Umm Sahm formation and
did not result in the production of commercial amounts of hydrocarbons. The WS-9
well was tested in the Dubaydib formation and yielded good shows of gas with
traces of light oil. The well was temporarily abandoned pending the evaluation
of additional data. The remainder of 1998 will be devoted to reprocessing and
remapping seismic data and conducting geological studies on the remaining
prospectivity of the block. The Company anticipates cumulative capital
expenditures of approximately $3 million through the end of 1998.
<PAGE> 14
SENEGAL, AFRICA
GENERAL
In December 1997, the Company was awarded a 45% working interest in the
approximately one million acre Thies block in the western portion of Senegal by
the state company of Societe des Petroles du Senegal ("Petrosen"). The Company
will serve as operator of the block. In consideration of the grant of the 45%
ownership, the Company has agreed to pay 90% of the first $6 million of costs to
install a pipeline and to drill two wells and, if the Company elects to proceed
further, to pay 67.5% of the next $6 million of costs for further exploration
and development. Thereafter, the Company's share of all costs and revenues will
be 45%.
Additionally, the Company will have the exclusive right to evaluate
approximately 7.5 million acres of Senegal's entire near-offshore holdings which
have been partitioned into six separate blocks. This includes the joint area
shared between Senegal and Guinee-Bissau and comprises portions of the Dome
Flore block. The Company will serve as operator of each of the six offshore
blocks and will have an 85% participating interest with the balance held by
Petrosen. The Company is obligated to spend $1 million to reprocess and evaluate
existing seismic data, after which it may elect to proceed with further
operations on any or all of the blocks.
LOCATION AND GEOLOGY
The one million acre, onshore Thies block is located immediately east of the
Sebikhotane block, which has proven production from Maastrichtian sandstones.
Deeper pay potential on the block has been demonstrated by the Gadiaga #2 well,
which was drilled and tested by Petrosen in March of 1997. The six near-offshore
blocks include Dome Flore, one of several salt domes known to exist offshore in
Senegal.
DRILLING AND DEVELOPMENT ACTIVITY
The Company is reprocessing 1,565 kilometers of 2 dimensional seismic data on
the Thies block prior to making a reinterpretation of the existing discoveries
and planning an exploration program. In the offshore areas, the Company is
reprocessing approximately 10,000 kilometers of 2 dimensional seismic data out
of a total data set of 24,000 kilometers. Following an evaluation of this data
set, the Company will select certain blocks for further exploration activity.
EVALUATION OF ADDITIONAL OPPORTUNITIES
The Company continues to evaluate and pursue additional domestic and
international opportunities which fit within the Company's business strategy.
The Company is currently evaluating certain exploration, development and/or
acquisition opportunities, but it is not presently known whether, or on what
terms, such evaluations will result in future agreements or acquisitions.
RESERVES
The following table sets forth information regarding estimates of proved
reserves at December 31, 1997 prepared by the Company and audited by Huddleston
& Co., Inc., independent petroleum engineers:
<TABLE>
<CAPTION>
CRUDE OIL AND CONDENSATE (MBBL)
--------------------------------
DEVELOPED UNDEVELOPED TOTAL
-------- ------- -------
<S> <C> <C> <C>
Venezuela(1) 68,868 25,803 94,671
Russia(2) 5,443 20,670 26,113
------- ------- -------
Total 74,311 46,473 120,784
======= ======= =======
<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 P&G, under
which all mineral rights are owned by the Government of Venezuela. See
"--South Monagas Unit, Venezuela."
(2) Although the Company estimates that there are substantial natural gas
reserves in the North Gubkinskoye Field, no natural gas reserves have
been recorded because of a lack of a ready market.
</TABLE>
<PAGE> 15
Estimates of commercially recoverable oil and gas reserves and of the future net
cash flows derived therefrom are based upon a number of variable factors and
assumptions, such as historical production from the subject properties,
comparison with other producing properties, the assumed effects of regulation by
governmental agencies and assumptions concerning future operating costs,
severance and excise taxes, export tariffs, abandonment costs, development costs
and workover and remedial costs, all of which may vary considerably from actual
results. All such estimates are to some degree speculative, and various
classifications of reserves are only attempts to define the degree of
speculation involved. For these reasons, estimates of the commercially
recoverable reserves of oil attributable to any particular property or group of
properties, the classification, cost and risk of recovering such reserves and
estimates of the future net cash flows expected therefrom, prepared by different
engineers or by the same engineers at different times, may vary substantially.
The difficulty of making precise estimates is accentuated by the fact that 46%
of the Company's total proved reserves were non-producing as of December 31,
1997. Therefore, the Company's actual production, revenues, severance and excise
taxes, export tariffs, development expenditures, workover and remedial
expenditures, abandonment expenditures and operating expenditures with respect
to its reserves will likely vary from estimates, and such variances may be
material.
In addition, actual future net cash flows will be affected by factors such as
actual production, supply and demand for oil, availability and capacity of
gathering systems and pipelines, changes in governmental regulations or taxation
and the impact of inflation on costs. The timing of actual future net revenue
from proved reserves, and thus their actual present value, can be affected by
the timing of the incurrence of expenditures in connection with development of
oil and gas properties. The 10% discount factor, which is required by the
Securities and Exchange Commission to be used to calculate present value for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
the oil and gas industry. Discounted present value, no matter what discount rate
is used, is materially affected by assumptions as to the amount and timing of
future production, which may and often do prove to be inaccurate. For the period
ending December 31, 1997, the Company reported $441.7 million of discounted
future net cash flows before income taxes from proved reserves based on the
Commission's required calculations.
PRODUCTION, PRICES AND LIFTING COST SUMMARY
The following table sets forth by country net production, average sales prices
and average lifting costs of the Company for the years ended December 31, 1997,
1996 and 1995:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER
--------------------------------------
1997 1996 1995
---------- ---------- ---------
<S> <C> <C> <C>
VENEZUELA
Net Crude Oil Production (Bbl) 15,394,807 12,647,987 5,456,473
Average Crude Oil Sales Price ($ per Bbl) $10.01 $10.82 $9.01
Average Lifting Costs ($ per Bbl) 2.24 1.40 1.19
RUSSIA (1)
Net Crude Oil Production (Bbl) 880,148 765,137 490,960
Average Crude Oil Sales Price ($ per Bbl) $11.28 $11.82 $12.25
Average Lifting Costs ($ per Bbl) 8.35 8.63 5.63
<FN>
(1) The presentation for Russia includes information for the nine months ended September
30, 1995 and the twelve months ended September 30, 1996 and 1997, the end of the
fiscal period for GEOILBENT. See Note 18 to the Company's Consolidated Financial
Statements.
</FN>
</TABLE>
<PAGE> 16
REGULATION
GENERAL
The Company's operations are affected by political developments and laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and costs.
Oil and gas industry legislation and agency regulation is periodically changed
for a variety of political, economic, environmental and other reasons. Numerous
governmental departments and agencies issue rules and regulations binding on the
oil and gas industry, some of which carry substantial penalties for the failure
to comply. The regulatory burden on the oil and gas industry increases the
Company's cost of doing business.
VENEZUELA
Venezuela requires environmental and other permits for certain operations
conducted in oil field development, such as site construction, drilling, and
seismic activities. As a contractor to P&G, Benton-Vinccler submits capital and
operating budgets to P&G for approval. Capital expenditures to comply with
Venezuelan environmental regulations relating to the reinjection of gas in the
field and water disposal were $12.8 million in 1997 and are expected to be $8.0
million in 1998. Benton-Vinccler also submits requests for permits for drilling,
seismic and operating activities to P&G, which then obtains such permits from
the Ministry of Energy and Mines and Ministry of Environment, as required.
Benton-Vinccler is also subject to income, municipal and value added taxes, and
must file certain monthly and annual compliance reports to SENIAT (the national
tax administration) and to various municipalities.
RUSSIA
GEOILBENT submits annual production and development plans, which include
information necessary for permits and approvals for its planned drilling,
seismic and operating activities, to local and regional governments and to the
Ministry of Fuel and Energy, Committee of Geology and Ministry of Economy.
GEOILBENT also submits annual production targets and quarterly export
nominations for oil pipeline transportation capacity to the Ministry of Fuel and
Energy. GEOILBENT is subject to customs, value added, and municipal and income
taxes. Various municipalities and regional tax inspectorates are involved in the
assessment and collection of these taxes. GEOILBENT must file operating and
financial compliance reports with several bodies, including the Ministries of
Fuel and Energy, Committee of Geology, Committee for Technical Mining
Monitoring, the Ministry of Ecology, and the State Customs Committee.
DRILLING, ACQUISITION AND FINDING COSTS
During the years ended December 31, 1997, 1996 and 1995, the Company spent
approximately $109 million, $108 million and $74 million, respectively, for
acquisitions of leases and producing properties, development and exploratory
drilling, production facilities and additional development activities such as
workovers and recompletions.
<PAGE> 17
The Company has drilled or participated in the drilling of wells as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------------
1997 1996 1995
---------------------- ---------------------- ----------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
WELLS DRILLED:
Exploratory:
Crude oil - - - - 3 1.020
Natural gas - - 1 .375 3 .970
Dry holes - - - - 1 .375
Development:(1)(2)
Crude oil 31 22.040 36 26.500 41 22.680
Natural Gas - - - - 1 .220
Dry Holes 1 .340 - - 1 .800
--------- --------- --------- --------- --------- ---------
TOTAL 32 22.380 37 26.875 50 26.065
========= ========= ========= ========= ========= =========
AVERAGE DEPTH OF WELLS (FEET) 6,659 8,008 7,847
PRODUCING WELLS (3):
Crude Oil 124 78.960 113 74.300 77 44.701
Natural Gas - - - - 8 2.024
<FN>
(1) In March 1995, the Company sold certain of its West Cote Blanche Bay Field interests in the field, a result of which
was to substantially eliminate the Company's future participation in recompletion and redrilling activities, and in
March 1996, the Company sold the remainder of its interests in the field.
(2) In addition to the activities set forth in the table, the Company participated in the successful reactivation of one
gross (.34 net) oil well in Russia during the year ended December 31, 1995.
(3) The information related to producing wells reflects wells the Company drilled, wells the Company participated in
drilling and producing wells the Company acquired.
</FN>
</TABLE>
At March 25, 1998, the Company was participating in the drilling of one well in
Venezuela, five wells in Russia and one well in California.
All of the Company's drilling activities are conducted on a contract basis with
independent drilling contractors. The Company does not own any drilling
equipment.
From commencement of operations through December 31, 1997, the Company added,
net of production and property sales, approximately 120.8 MBOE of proved
reserves through purchases of reserves-in-place, discoveries of oil and natural
gas reserves, extensions of existing producing fields and revisions of
previously estimated reserves, for which the finding costs were 2.30 per BOE.
The Company's estimate of future development costs for its undeveloped proved
reserves at December 31, 1997 was 1.96 BOE. The estimated future development
costs are based upon the Company's anticipated cost of developing its
non-producing proved reserves, which costs are calculated using historical costs
for similar activities.
<PAGE> 18
ACREAGE
The following table summarizes the developed and undeveloped acreage owned,
leased or under concession as of December 31, 1997.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
----------------- ------------------------
GROSS NET GROSS NET
------ ------ --------- ---------
<S> <C> <C> <C> <C>
Venezuela 9,950 7,960 673,893 276,114
Russia 16,080 5,467 149,680 50,891
China - - 6,339,117 6,269,558
Jordan - - 1,192,752 1,192,752
Senegal 1,280 576 997,399 448,830
United States 5,002 1,700 18,100 10,696
------ ------ --------- ---------
Total 32,312 15,703 9,370,941 8,248,841
====== ====== ========= =========
</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, 1997, the Company had 71 employees augmented from time to time
with independent consultants, as required. Benton-Vinccler had 175 employees,
and GEOILBENT had 230 employees.
TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE
All Venezuelan reserves are attributable to an operating service agreement
between Benton-Vinccler and P&G, under which all mineral rights are owned by the
Government of Venezuela. With regard to Russian acreage, GEOILBENT has obtained
certain documentation from appropriate regulatory bodies in Russia which the
Company believes is adequate to establish GEOILBENT's right to develop, produce
and market oil and gas from the North Gubkinskoye Field in Russia.
The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea,
with an option for another one million acres under certain circumstances, and
lies within an area which is the subject of a territorial dispute between the
People's Republic of China and Vietnam. Vietnam has executed an agreement on a
portion of the same offshore acreage with Conoco, a unit of DuPont Corporation.
The territorial dispute has existed for many years, and there has been limited
exploration and no development activity in the area under dispute. It is
uncertain when or how this dispute will be resolved, and under what terms the
various countries and parties to the agreements may participate in the
resolution, although certain proposed economic solutions currently under
discussion would result in the Company's interest being reduced.
At the time of acquisition of undeveloped acreage in the United States, the
Company conducts a limited title investigation. A title opinion from a qualified
law firm is obtained prior to drilling any given U.S. prospect. Title to
presently producing properties is investigated by a qualified law firm prior to
purchase. The Company believes its method of investigating the title to these
domestic properties is consistent with general practices in the oil and gas
industry and is designed to enable the Company to acquire title which is
generally considered to be acceptable in the oil and gas industry.
<PAGE> 19
GLOSSARY
When the following terms are used in the text they have the meanings indicated.
MCF. "Mcf" means thousand cubic feet. "Mmcf" means million cubic feet.
"Bcf" means billion cubic feet. "Tcf" means trillion cubic feet.
BBL. "Bbl" means barrel. "MBbl" means thousand barrels. "MMBbl" means
million barrels. "BBbl" means billion barrels.
BOE. "BOE" means barrels of oil equivalent, which are determined using the
ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf
of natural gas so that six Mcf of natural gas is referred to as one barrel of
oil equivalent or "BOE". "MBOE" means thousands of barrels of oil equivalent.
"MMBOE" means millions of barrels of oil equivalent.
CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with
exploratory and development drilling (including exploratory dry holes);
leasehold acquisitions; seismic data acquisitions; geological, geophysical and
land-related overhead expenditures; delay rentals; producing property
acquisitions; and other miscellaneous capital expenditures.
COMPLETION COSTS. "Completion Costs" means, as to any well, all those
costs incurred after the decision to complete the well as a producing well.
Generally, these costs include all costs, liabilities and expenses, whether
tangible or intangible, necessary to complete a well and bring it into
production, including installation of service equipment, tanks, and other
materials necessary to enable the well to deliver production.
DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional
well to the same reservoir as other producing wells on a lease, or drilled on an
offset lease not more than one location away from a well producing from the same
reservoir.
EXPLORATORY WELL. An "Exploratory Well" is a well drilled in search of a
new and as yet undiscovered pool of oil or gas, or to extend the known limits of
a field under development.
FINDING COST. "Finding Cost", expressed in dollars per BOE, is calculated
by dividing the amount of total capital expenditures related to acquisitions,
exploration and development costs (reduced by proceeds for any sale of oil and
gas properties) by the amount of total net reserves added or reduced as a result
of property acquisitions and sales, drilling activities and reserve revisions
during the same period.
FUTURE DEVELOPMENT COST. "Future Development Cost" of proved nonproducing
reserves, expressed in dollars per BOE, is calculated by dividing the amount of
future capital expenditures related to development properties by the amount of
total proved non-producing reserves associated with such activities.
GROSS ACRES OR WELLS. "Gross Acres or Wells" are the total acres or wells,
as the case may be, in which an entity has an interest, either directly or
through an affiliate.
LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a
producing formation to the surface, consisting of the costs incurred to operate
and maintain wells and related equipment and facilities, including labor costs,
repair and maintenance, supplies, insurance, production, severance and windfall
profit taxes.
NET ACRES OR WELLS. A party's "Net Acres" or "Net Wells" are calculated by
multiplying the number of gross acres of gross wells in which that party has an
interest by the fractional interest of the party in each such acre or well.
PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved
Developed Reserves expected to be produced from existing completion intervals
now open for production in existing wells. "Producing Properties" are properties
to which Producing Reserves have been assigned by an independent petroleum
engineer.
<PAGE> 20
PROVED DEVELOPED RESERVES. "Proved Developed Reserves" are Proved Reserves
which can be expected to be recovered through existing wells with existing
equipment and operating methods.
PROVED RESERVES. "Proved Reserves" are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known oil and gas reservoirs under existing economic and operating conditions,
that is, on the basis of prices and costs as of the date the estimate is made
and any price changes provided for by existing conditions.
PROVED UNDEVELOPED RESERVES. "Proved Undeveloped Reserves" are Proved
Reserves which can be expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion.
RESERVES. "Reserves" means crude oil and natural gas, condensate and
natural gas liquids, which are net of leasehold burdens, are stated on a net
revenue interest basis, and are found to be commercially recoverable.
ROYALTY INTEREST. A "Royalty Interest" is an interest in an oil and gas
property entitling the owner to a share of oil and gas production (or the
proceeds of the sale thereof) free of the costs of production.
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS. The "Standardized Measure
of Future Net Cash Flows" is a method of determining the present value of Proved
Reserves. The future net revenues from Proved Reserves are estimated assuming
that oil and gas prices and production costs remain constant. The resulting
stream of revenues is then discounted at the rate of 10% per year to obtain a
present value.
3-D SEISMIC. "3-D Seismic" is the method by which a three dimensional
image of the earth's subsurface is created through the interpretation of seismic
data. 3-D surveys allow for a more detailed understanding of the subsurface than
do conventional surveys and contribute significantly to field appraisal,
development and production.
UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and gas acreage
(including, in applicable instances, rights in one or more horizons which may be
penetrated by existing wellbores, but which have not been tested) to which
Proved Reserves have not been assigned by independent petroleum engineers.
ITEM 2. PROPERTIES
The principal executive offices of the Company are located in leased space in
Carpinteria, California. The lease covering this facility expires in December
2004. The Company also has other offices located in leased space, none of which
individually or in the aggregate are material. Additionally, the Company has
entered into a 15 year lease agreement for office space currently under
construction in Carpinteria, California. It is anticipated that the building
will be ready for occupancy in late 1998. The Company will lease the entire
building (50,000 square feet) for $72,500 per month, subject to adjustments for
tenant improvements, with annual rent adjustments based on certain changes in
the Consumer Price Index. The Company intends to sublet the portion of the new
building which would not be immediately needed for operations and to sublet the
space currently occupied in Carpinteria. For information concerning the location
and character of the Company's oil and gas properties and interests, see Item
1.
ITEM 3. LEGAL PROCEEDINGS
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of the West Cote Blanche Bay Properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that at the time of
Tesla's acquisition, it was insolvent and that it paid a price in excess of the
fair value of the property. The Company intends to vigorously contest the suit
and in its management's opinion, while it is unlikely that the suit will result
in a material adverse effect on the Company's financial statements, it is too
early to assess the probability of such an outcome.
<PAGE> 21
On June 13, 1994, Charles Agnew and other limited partners in several limited
partnerships formed by the Company brought an action in the Superior Court of
California, County of Ventura, against the Company for alleged actions and
omissions of the Company in operating the partnerships and alleged
misrepresentations made by the Company in selling the limited partnership
interests. The claimants seek an unspecified amount of actual and punitive
damages. On May 17, 1995, the Company agreed to a binding arbitration proceeding
with respect to such claims, which is currently in the discovery stage. The
Company will be forced to spend time and financial resources to defend or
resolve these matters. In January 1996, the Company acquired all of the
interests in three of the limited partnerships which are the subject of the
arbitration, in exchange for shares of, and warrants to purchase shares of, the
Company's common stock. In the arbitration proceeding, if any liability is found
to exist, the arbitrator will determine the amount of any damages, and may
consider all distributions made to the partners, including the consideration
received in the exchange offer, in determining the extent of damages, if any.
However, there can be no assurance that an arbitrator will consider such factors
in his or her determination of damages if the allegations are found to be true
and damages are awarded. In the normal course of the Company's business, there
are various legal proceedings outstanding. In the opinion of management, these
proceedings will not have a material adverse effect on the Company's financial
statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the three month period ended December 31, 1997, no matter was submitted
to a vote of security holders.
<PAGE> 22
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Company's Common Stock is traded on the New York Stock Exchange ("NYSE")
under the symbol "BNO." For the period represented below, the Company's Common
Stock was traded on the NASDAQ Stock Market under the symbol "BNTN" until April
29, 1997, when the Company's Common Stock began trading on the NYSE. As of
December 31, 1997, there were 29,522,110 shares of Common Stock outstanding held
of record by approximately 1,102 stockholders. The following table sets forth
the high and low sales prices for the Company's Common Stock reported on the
NASDAQ from January 1, 1996 to April 28, 1997 and on the NYSE thereafter.
<TABLE>
<CAPTION>
YEAR QUARTER HIGH LOW
---------------------------------------------------------------------------------
<S> <C> <C>
1996
First quarter $ 16.63 $ 11.25
Second quarter 22.13 15.63
Third quarter 25.38 18.38
Fourth quarter 28.63 19.75
1997
24.75 14.63
First quarter
17.13 12.63
Second quarter
19.25 13.50
Third quarter
21.88 11.25
Fourth quarter
1998
First quarter (through March 25) 13.69 9.75
</TABLE>
On March 25, 1998, the last sales price for the Common Stock as reported by NYSE
was $11.81 per share.
The Company's policy is to retain its earnings to support the growth of the
Company's business. Accordingly, the Board of Directors of the Company has never
declared cash dividends on its Common Stock. The Company's indentures currently
restrict the declaration and payment of any cash dividends.
<PAGE> 23
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data for the Company for each of
the five years in the period ended December 31, 1997, are derived from the
Company's audited consolidated financial statements. The consolidated financial
data below should be read in conjunction with the Company's Consolidated
Financial Statements and related notes thereto and Item 7. -- Management's
Discussion and Analysis of Financial Condition and Results of Operations
contained elsewhere in this report.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------
1997 1996 1995(2) 1994 1993
-------- -------- -------- -------- --------
(amounts in thousands, except per share data)
STATEMENT OF OPERATIONS:
<S> <C> <C> <C> <C> <C>
Total revenues $179,019 $165,066 $ 65,068 $ 34,705 $ 7,503
Lease operating costs and production taxes 41,887 24,518 10,703 9,531 5,110
Depletion, depreciation and amortization 47,592 34,525 17,411 10,298 2,633
General and administrative expense 23,436 18,906 9,411 5,242 2,631
Interest expense 24,245 16,128 7,497 3,888 1,958
Partnership exchange expenses - 2,140 - - -
Litigation settlement expenses - - 1,673 - -
-------- -------- -------- -------- --------
Income (loss) before income taxes, minority
interest and extraordinary charge 41,859 68,849 18,373 5,746 (4,829)
Income taxes 17,477 20,508 2,478 698 -
-------- -------- -------- -------- --------
Income (loss) before minority interest and
extraordinary charge 24,382 48,341 15,895 5,048 (4,829)
Minority interest 6,333 9,984 5,304 2,094 -
-------- -------- -------- -------- --------
Income (loss) before extraordinary charge 18,049 38,357 10,591 2,954 (4,829)
Extraordinary charge for early retirement of
debt, net of tax benefit of $879 - 10,075 - - -
-------- -------- -------- -------- --------
Net income (loss) $ 18,049 $ 28,282 $ 10,591 $ 2,954 $ (4,829)
======== ======== ======== ======== ========
Net income (loss) per common share:
Basic:
Income (loss) before extraordinary $ 0.62 $ 1.42 $ 0.42 $ 0.12 $ (0.26)
charge
Extraordinary charge - 0.38 - - -
-------- -------- -------- -------- --------
Net income (loss) $ 0.62 $ 1.04 $ 0.42 $ 0.12 $ (0.26)
======== ======== ======== ======== ========
Diluted:
Income (loss) before extraordinary $ 0.59 $ 1.29 $ 0.40 $ 0.12 $ (0.26)
charge
Extraordinary charge - 0.34 - - -
-------- -------- -------- -------- --------
Net income (loss) $ 0.59 $ 0.95 $ 0.40 $ 0.12 $ (0.26)
======== ======== ======== ======== ========
Weighted average common shares outstanding:
Basic 29,119 27,088 25,084 24,851 18,609
Diluted 30,834 29,813 26,673 25,325 18,609
</TABLE>
<PAGE> 24
<TABLE>
<CAPTION>
AT DECEMBER 31,
-----------------------------------------------------------------
1997 1996 1995 (2) 1994 1993
--------- --------- --------- --------- ---------
BALANCE SHEET DATA: (amounts in thousands)
<S> <C> <C> <C> <C> <C>
Working capital (deficit) $ 165,945 $ 98,417 $ (2,888) $ 21,785 $ 26,635
Total assets 584,277 435,745 214,750 162,561 108,635
Long-term obligations, net of current portion 280,016 175,028 49,486 31,911 11,788
Stockholders' equity (1) 197,732 174,899 103,681 88,259 84,021
<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. See Note 18 to the Consolidated Financial
Statements.
</FN>
</TABLE>
<PAGE> 25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
PRINCIPLES OF CONSOLIDATION AND ACCOUNTING METHODS
The Company includes the results of operations of Benton-Vinccler in its
consolidated financial statements and reflects the 20% ownership interest of
Vinccler as a minority interest. Beginning in 1995, GEOILBENT has been included
in the consolidated financial statements based on a fiscal period ending
September 30. Results of operations in Russia reflect the nine months ended
September 30, 1995 and the twelve months ended September 30, 1996 and 1997. The
Company's investment in GEOILBENT is proportionately consolidated based on the
Company's ownership interest, and for oil and gas reserve information, the
Company reports its 34% share of the reserves attributable to GEOILBENT.
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all acquisition, exploration,
and development costs incurred. The Company accounts for its oil and gas
properties using cost centers on a country by country basis. Proceeds from sales
of oil and gas properties are credited to the full-cost pools. Capitalized costs
of oil and gas properties are amortized within the cost centers on an overall
unit-of-production method using proved oil and gas reserves as audited by
independent petroleum engineers. Costs amortized include all capitalized costs
(less accumulated amortization), the estimated future expenditures (based on
current costs) to be incurred in developing proved reserves, and estimated
dismantlement, restoration and abandonment costs (see Note 1 of Notes to the
Company's Consolidated Financial Statements).
The following discussion of the results of operations and financial condition as
of December 31, 1997 and 1996 and for each of the years in the three year period
ended December 31, 1997, respectively, should be read in conjunction with the
Company's Consolidated Financial Statements and related Notes thereto.
RESULTS OF OPERATIONS
The Company's results of operations for the year ended December 31, 1997,
primarily reflect the substantial growth of Benton-Vinccler in Venezuela. During
1997, Benton-Vinccler accounted for more than 90% of the Company's production,
oil and gas sales and net income. Other major influences on the Company's
results of operations during the year ended December 31, 1997 were the
continuing maturation of the Uracoa oil field resulting in higher water
handling, gas handling, workover, transportation and chemical costs and the
issuance of $115.0 million of senior unsecured notes.
The following table presents selected expense items as a percentage of oil and
gas sales:
<TABLE>
<CAPTION>
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Lease Operating Costs and Production Taxes 25.5% 16.6% 17.2%
Depletion, Depreciation and Amortization 29.0 23.4 28.0
General and Administrative 14.3 12.8 15.1
Interest 14.8 10.9 12.1
</TABLE>
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).
<PAGE> 26
By comparison, the Company had revenues of $165.1 million for the year ended
December 31, 1996. Expenses incurred during the period consisted of lease
operating costs and production taxes of $24.5 million, depletion, depreciation
and amortization expense of $34.5 million, general and administrative expense of
$18.9 million, interest expense of $16.1 million, partnership exchange expense
of $2.1 million, income tax expense of $20.5 million, minority interest of $10.0
million and an extraordinary charge for early retirement of debt, net of tax
benefit, of $10.1 million. Net income for the period was $28.3 million or $0.95
per share (diluted).
Revenues increased $13.9 million, or 8%, during the year ended December 31, 1997
compared to the corresponding period of 1996 primarily due to increased oil
sales in Venezuela and increased investment earnings partially offset by the
gain on sale of properties in 1996. Sales quantities for the year ended December
31, 1997 from Venezuela and Russia were 15,394,807 Bbls and 880,148 Bbls,
respectively, compared to 12,647,987 Bbls and 765,137 Bbls, respectively, for
the year ended December 31, 1996. Prices for crude oil per Bbl averaged $10.01
(pursuant to terms of an operating service agreement) from Venezuela and $11.28
from Russia for the year ended December 31, 1997 compared to $10.82 and $11.82,
respectively, for the year ended December 31, 1996. Revenues for 1997 were
increased by a foreign exchange gain of $2.3 million compared to a gain of $2.8
million in 1996.
Lease operating costs and production taxes increased $17.4 million, or 71%,
during the year ended December 31, 1997 compared to 1996 primarily due to
continued growth of the Company's Venezuelan operations, as well as the
continuing maturation of the Uracoa oil field resulting in higher water
handling, gas handling, workover, transportation and chemical costs. Depletion,
depreciation and amortization increased $13.1 million, or 38%, during the year
ended December 31, 1997 compared to the corresponding period in 1996. Depletion
expense per BOE produced from Venezuela and Russia during the year ended
December 31, 1997 was $2.83 and $3.50, respectively, compared to $2.33 and
$3.59, respectively, during the previous year. General and administrative
expenses increased $4.5 million, or 24% during the year ended December 31, 1997
compared to 1996 primarily due to the Company's increased corporate activity
associated with the growth of the Company's business and increased Venezuelan
municipal taxes (which are a function of growing oil revenues and increased tax
rates). Interest expense increased $8.1 million, or 50%, in 1997 compared to
1996 primarily due to the issuance of $125 million in senior unsecured notes in
May 1996 and to the issuance of $115 million in senior unsecured notes in
November 1997. Income tax expense decreased $3.0 million, or 15%, during the
year ended December 31, 1997 compared to 1996 primarily due to decreased taxable
income in Venezuela. The net income attributable to the minority interest
decreased $3.7 million, or 37%, for 1997 compared to 1996 as a result of the
decreased profitability of Benton-Vinccler's operations in Venezuela.
YEARS ENDED DECEMBER 31, 1996 AND 1995
The Company had revenues of $165.1 million for the year ended December 31, 1996.
Expenses incurred during the period consisted of lease operating costs and
production taxes of $24.5 million, depletion, depreciation and amortization
expense of $34.5 million, general and administrative expense of $18.9 million,
interest expense of $16.1 million, partnership exchange expense of $2.1 million,
income tax expense of $20.5 million, minority interest of $10.0 million and an
extraordinary charge for early retirement of debt, net of tax benefit, of $10.1
million. Net income for the period was $28.3 million or $0.95 per share
(diluted).
By comparison, the Company had revenues of $65.1 million for the year ended
December 31, 1995. Expenses incurred during the period consisted of lease
operating costs and production taxes of $10.7 million, depletion, depreciation
and amortization expense of $17.4 million, general and administrative expense of
$9.4 million, interest expense of $7.5 million, litigation settlement expenses
of $1.7 million, income tax expense of $2.5 million and a minority interest of
$5.3 million. Net income for the period was $10.6 million or $0.41 per share
(diluted).
Revenues increased $100.0 million, or 154%, during the year ended December 31,
1996 compared to the corresponding period of 1995 primarily due to increased oil
sales in Venezuela. Sales quantities for the year ended December 31, 1996 from
Venezuela and Russia were 12,647,987 Bbls and 765,137 Bbls, respectively,
compared to 5,456,473 Bbls and 490,960 Bbls, respectively, for the year ended
December 31, 1995. Prices for crude oil per Bbl averaged $10.82 (pursuant to
terms of an operating service agreement) from Venezuela and $11.82 from Russia
for the year ended December 31, 1996 compared to $9.01 and $12.25, respectively,
for the year ended December 31, 1995. Domestic sales quantities for the year
ended December 31, 1996 were 6,589 Bbls of crude oil and condensate and
1,523,106 Mcf of natural gas compared to 68,975 Bbls of crude oil and 3,784,830
Mcf of natural gas for the year ended December 31, 1995. Domestic prices per Bbl
for crude oil and per Mcf for natural gas averaged $19.70 and $3.04 during the
year ended December 31, 1996 compared to $15.79 and $1.77 during the year ended
December 31, 1995. Revenues for the year ended December 31, 1996 were reduced by
a loss of $2.9 million related to a commodity
<PAGE> 27
hedge agreement compared to a loss of $0.7 million in 1995. Revenues for 1996
were increased by a foreign exchange gain of $2.8 million compared to a gain of
$1.0 million in 1995.
Expenses increased during 1996 as Benton-Vinccler's operations continued to grow
significantly, but decreased as a percentage of oil and gas sales. Lease
operating costs and production taxes increased $13.8 million, or 129%, during
the year ended December 31, 1996 compared to 1995, partially offset by the sale
of the Company's remaining interest in the West Cote Blanche Bay, Rabbit Island
and Belle Isle Fields. Depletion, depreciation and amortization increased $17.1
million, or 98%, during the year ended December 31, 1996 compared to the
corresponding period in 1995. Depletion expense per BOE produced from Venezuela,
United States and Russia during the year ended December 31, 1996 was $2.33,
$6.55 and $3.59, respectively, compared to $2.09, $5.98 and $3.08, respectively,
during the previous year. The increase in general and administrative expenses of
$9.5 million, or 101%, during the year ended December 31, 1996 compared to 1995
was primarily due to the implementation of certain consulting and related
arrangements among Benton-Vinccler, the Company and Vinccler, Venezuelan
municipal taxes (which are a function of growing oil revenues) and the Company's
increased corporate activity associated with the growth of the Company's
business. Interest expense increased $8.6 million, or 115%, in 1996 compared to
1995 primarily due to the issuance of $125 million in senior unsecured notes in
May 1996. The Company incurred partnership exchange expense of $2.1 million
during the year ended December 31, 1996 as a result of the completion of an
exchange offer resulting in the liquidation of three limited partnerships (see
Note 2 of Notes to the Consolidated Financial Statements). Income tax expense
increased $18.0 million, or 720%, during the year ended December 31, 1996
compared to 1995 primarily due to increased taxable income in Venezuela. The net
income attributable to the minority interest increased $4.7 million, or 89%, for
1996 compared to 1995 as a result of the increased profitability of
Benton-Vinccler's operations in Venezuela.
INTERNATIONAL OPERATIONS
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%. However, Benton-Vinccler reported a significantly lower effective
tax rate for 1996 due to significant non-cash tax deductible expenses resulting
from devaluations in Venezuela when Benton-Vinccler had net monetary liabilities
in U.S. dollars. The Company cannot predict the timing or impact of future
devaluations in Venezuela.
A 3-D seismic survey is being conducted over the southwestern portion of the
Delta Centro Block in Venezuela with an expected total cost to the Company
during 1998 of approximately $4.0 million. Following the initial interpretation
of the seismic data, an initial exploration well is expected to be drilled
during the fourth quarter of 1998 at a cost to the Company of approximately $4.3
million. Subsequent seismic and drilling programs will be based on the results
of the 1997-1998 activity. The Company's operations related to Delta Centro will
be subject to oil and gas industry taxation, which currently provides for
royalties of 16.66% and income taxes of 67.7%.
GEOILBENT is subject to a statutory income tax rate of 35%. GEOILBENT has also
been subject to various other tax burdens, including an oil export tariff which
was terminated effective July 1, 1996. Excise, pipeline and other taxes continue
to be levied on all oil producers and certain exporters. The Russian regulatory
environment continues to be volatile and the Company is unable to predict the
impact of taxes, duties and other burdens for the future.
In December 1996, the Company acquired Crestone, a privately held company
headquartered in Denver, Colorado. Crestone's principal asset is a petroleum
contract with CNOOC for an area known as Wan'An Bei, WAB-21. The WAB-21
petroleum contract covers 6.2 million acres in the South China Sea, with an
option for another one million acres under certain circumstances, and lies
within an area which is the subject of a territorial dispute between the
People's Republic of China and Vietnam. Vietnam has also executed an agreement
on a portion of the same offshore acreage with Conoco, a unit of DuPont
Corporation. The territorial dispute has existed for many years, and there has
been limited exploration and no development activity in the area under dispute.
It is uncertain when or how this dispute will be resolved, and under what terms
the various countries and parties to the agreements may participate in the
resolution, although certain proposed economic solutions currently under
discussion would result in the Company's interest being reduced. The Company,
through Crestone, has submitted plans and budgets to CNOOC for an initial
seismic program to survey the area. However, exploration activities will be
subject to resolution of such territorial dispute. The Company has recorded no
reserves attributable to this petroleum contract.
In August 1997, the Company acquired the rights to a PSA with Jordan's NRA to
explore, develop and produce the Sirhan block in southeastern Jordan. The Sirhan
block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over eight years. The
<PAGE> 28
Company is obligated to spend $5.1 million in the first exploration phase, which
is expected to last approximately two years. If the Company ultimately elects to
continue through phases two and three, it would be obligated to spend an
additional $18.0 million over the succeeding six years.
In October 1997, the Company signed a farmout agreement with Shell whereby the
Company will acquire a 50% participation interest in Shell's Liaohe area onshore
exploration project in northeast China. Shell holds a petroleum contract with
CNPC to explore and develop the deep rights in the Qingshui Block, a 563 square
kilometer area (approximately 140,000 acres) in the delta of the Liaohe River.
Shell will be the operator of the project. The Company is required to pay to
Shell 50% of Shell's costs to date, estimated to be approximately $4.0 million
($2 million to the Company) and to pay 100% of the costs for the phase one
exploration period, with a maximum required expenditure of $8.0 million. If the
first phase of the exploration period results in a commercial discovery and if
the Company elects to continue to phase two, then the Company will pay 100% of
the costs of the second phase of the exploration period, with a maximum required
expenditure of $8.0 million. The Company and Shell will be responsible for the
costs of the third exploration phase and the costs of development activities
associated with any of the three phases in proportion to their interests.
In December 1997, the Company signed a memorandum of understanding with Petrosen
to receive a minimum 45% working interest in and to operate the approximately
one million acre onshore Thies Block in western Senegal. In addition, the
Company obtained exclusive rights from Petrosen to evaluate and reprocess
geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea Bissau border in the south, and to choose
certain blocks for further data acquisition and exploration drilling. The
Company's working interest in any offshore discovery will be 85% with the
remainder held by Petrosen.
The Company's $5.4 million work commitment on the Thies Block where Petrosen has
recently drilled and completed the Gadiaga #2 discovery well, consists of
hooking up the existing well, drilling two additional wells and constructing a
41 kilometer (approximately 25 mile) gas pipeline en route to Senegal's main
electric generating facility near Dakar. The Company's minimum commitment
related to the offshore blocks involves seismic reprocessing to be followed by
additional data acquisition and drilling at the Company's discretion.
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION
The Company's results of operations and cash flow are affected by changing oil
and gas prices. However, the Company's Venezuelan revenues are based on a fee
adjusted quarterly by the percentage change of a basket of crude oil prices
instead of by absolute dollar changes, which dampens both any upward and
downward effects of changing prices on the Company's Venezuelan revenues and
cash flows. If the price of oil and gas increases, there could be an increase in
the cost to the Company for drilling and related services because of increased
demand, as well as an increase in revenues. Fluctuations in oil and gas prices
may affect the Company's total planned development activities and capital
expenditure program.
There are presently no restrictions in either Venezuela or Russia that restrict
converting U.S. dollars into local currency. However, from June 1994 through
April 1996, Venezuela implemented exchange controls which significantly limited
the ability to convert local currency into U.S. dollars. Because payments made
to Benton-Vinccler are made in U.S. dollars into its United States bank account,
and Benton-Vinccler is not subject to regulations requiring the conversion or
repatriation of those dollars back into Venezuela, the exchange controls did not
have a material adverse effect on Benton-Vinccler or the Company. Currently,
there are no exchange controls in Venezuela or Russia that restrict conversion
of local currency into U.S. dollars.
Within the United States, inflation has had a minimal effect on the Company, but
it is potentially an important factor in results of operations in Venezuela and
Russia. With respect to Benton-Vinccler and GEOILBENT, substantially all of the
sources of funds, including the proceeds from oil sales, the Company's
contributions and credit financings, are denominated in U.S. dollars, while
local transactions in Russia and Venezuela are conducted in local currency. If
the rate of increase in the value of the dollar compared to the bolivar
continues to be less than the rate of inflation in Venezuela, then inflation
could be expected to have an adverse effect on Benton-Vinccler.
During the year ended December 31, 1997, the Company realized net foreign
exchange gains, primarily as a result of the decline in the value of the
Venezuelan bolivar and the Russian rouble during periods when the Company's
Venezuela-related subsidiaries and GEOILBENT had substantial net monetary
liabilities denominated in bolivares and roubles. During the year ended December
31, 1997, the Company's net foreign exchange gains attributable to its
<PAGE> 29
Venezuelan and Russian operations were $2.0 million and $0.3 million,
respectively. However, there are many factors affecting foreign exchange rates
and resulting exchange gains and losses, many of which are beyond the control of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the U.S. dollar. It is not possible to predict the extent
to which the Company may be affected by future changes in exchange rates and
exchange controls.
CAPITAL RESOURCES AND LIQUIDITY
The oil and gas industry is a highly capital intensive business. The Company
requires capital principally to fund the following costs: (i) drilling and
completion costs of wells and the cost of production and transportation
facilities; (ii) geological, geophysical and seismic costs; and (iii)
acquisition of interests in oil and gas properties. The amount of available
capital will affect the scope of the Company's operations and the rate of its
growth.
The net funds raised and/or used in each of the operating, investing and
financing activities for each of the years ended December 31, are summarized in
the following table and discussed in further detail below:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------------
(In thousands)
1997 1996 1995
---------- ---------- ---------
<S> <C> <C> <C>
Net cash provided by operating activities $ 93,948 $ 84,852 $ 32,349
Net cash used in investing activities (216,028) (164,772) (53,644)
Net cash provided by financing activities 101,588 106,172 13,282
---------- ---------- ---------
Net increase (decrease) in cash $ (20,492) $ 26,252 $ (8,013)
========== ========== =========
</TABLE>
At December 31, 1997, the Company had current assets of $224.3 million and
current liabilities of $58.4 million resulting in working capital of $165.9
million and a current ratio of 3.84:1. This compares to the Company's working
capital of $98.4 million and a current ratio of 2.89:1 at December 31, 1996. The
increase of $67.5 million was due primarily to the issuance of $115 million of
senior unsecured notes partially offset by expenditures related to the
continuing development of the South Monagas Unit in Venezuela.
CASH FLOW FROM OPERATING ACTIVITIES. During 1997, 1996 and 1995, net cash
provided by operating activities was approximately $93.9 million, $84.9 million
and $32.3 million, respectively. Cash flow from operating activities increased
by $9.0 million and $52.6 million in 1997 and 1996, respectively, over the prior
years due primarily to increased oil and gas production in Venezuela.
CASH FLOW FROM INVESTING ACTIVITIES. During 1997, 1996 and 1995, the Company had
drilling and production related capital expenditures of approximately $109.8
million, $95.5 million and $68.3 million, respectively. Of the 1997
expenditures, $96.7 million was attributable to the development of the South
Monagas Unit in Venezuela, $2.7 million related to the development of the North
Gubkinskoye Field in Russia, $3.1 million related to a 3-D seismic survey in the
Delta Centro Block in Venezuela, $2.7 million related to the development of the
Gaviota lease in Santa Barbara County, California, $1.3 million related to the
development of the Sirhan Block in Jordan, and $3.3 million was attributable to
other projects. The Company also sold certain oil and gas properties for net
proceeds of approximately $34.6 million and $15.4 million in 1996 and 1995,
respectively.
The Company expects 1998 capital expenditures of approximately $125.0 million,
including $22.0 million in expenditures for Russia, net to the Company's
interest (which will be funded from borrowings under the EBRD Credit Facility,
cash flow from operations or other financings). Funding for the currently
anticipated 1998 capital expenditures is expected to come from working capital,
cash flow from operations or sales of property interests. The Company's
indentures contain provisions which restrict the manner in which the Company can
invest in certain of its current operations, including Geoilbent. Although the
Company believes it has sufficient funding for its expected capital expenditures
from working capital and cash flow from operations or sales of property
interests, the Company may be restricted in the manner of funding certain of
such capital expenditures due to such restrictions in the indentures.
The Company continues to evaluate and pursue domestic and international
opportunities which fit within the Company's business strategy. The Company is
currently evaluating certain exploration, development and/or acquisition
opportunities, but it is not presently known whether, or on what terms, such
evaluations will result in future agreements or acquisitions.
<PAGE> 30
CASH FLOW FROM FINANCING ACTIVITIES. In May 1996, the Company issued $125.0
million in 11.625% senior unsecured notes due May 1, 2003. Interest on the notes
is due May 1 and November 1 of each year. The indenture agreement provides for
certain limitations on liens, additional indebtedness, certain investment and
capital expenditures, dividends, mergers and sales of assets. At December 31,
1997, the Company was in compliance with all covenants of the indenture.
In November 1997, the Company issued $115.0 million in 9.375% senior unsecured
notes due November 1, 2007. The Company subsequently repurchased $10 million of
the notes at their par value. The indenture agreement provides for certain
limitations on liens, additional indebtedness, certain investment and capital
expenditures, dividends, mergers and sales of assets. At December 31, 1997, the
Company was in compliance with all covenants of the indenture. The proceeds from
the notes will be used for general corporate purposes, including the Company's
ongoing exploration and development programs.
The EBRD and IMB have agreed to lend a total of $65 million to GEOILBENT (owned
34% by the Company) under parallel reserve-based, non-recourse loan agreements.
Initial funding of $10.2 million and $1.8 million occurred in October 1997 and
January 1998. The proceeds from the loans will be used by GEOILBENT to develop
the North Gubkinskoye and Prisklonovoye fields in West Siberia, Russia.
Additional borrowings will be based on achieving certain reserve and production
milestones. The Company's share of the borrowings are not included in the
accompanying financial statements because they occurred subsequent to September
30, 1997, the end of the fiscal period for GEOILBENT (see Note 1 of Notes to the
Consolidated Financial Statements).
YEAR 2000 COMPLIANCE
The Company does not expect the cost of converting its computer systems to year
2000 compliance will be material to its financial condition. The Company
believes that it will be able to achieve year 2000 compliance by the end of
1999, and does not currently anticipate any disruption in its operations as a
result of any failure by the Company to be in compliance. The Company does not
currently have any information concerning the year 2000 compliance status of its
suppliers and customers.
STOCK REPURCHASE PROGRAM
In June 1997, the Board of Directors instituted a treasury stock repurchase
program under which the Company is authorized to purchase up to 1.5 million
shares of its common stock. The shares will be used for re-issuance in
connection with the Company's employee stock option plan, treasury stock or for
other corporate purposes to be determined in the future. During 1997, the
Company repurchased 50,000 shares at an average price of $13.99 per share.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The information required by this item is included herein on pages S-1 through
S-25.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported under this item.
<PAGE> 31
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
*
ITEM 11. EXECUTIVE COMPENSATION
*
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
*
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
*
* Reference is made to information under the captions "Election of
Directors", "Executive Officers", "Executive Compensation", "Security
Ownership of Certain Beneficial Owners and Management", and "Certain
Relationships and Related Transactions" in the Company's Proxy Statement
for the 1998 Annual Meeting of Stockholders.
<PAGE> 32
<TABLE>
<CAPTION>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
<S> <C>
(a) 1. Index to Financial Statements: Page
Independent Auditors' Report ...............................................................S-1
Consolidated Balance Sheets at December 31, 1997 and 1996 ..................................S-2
Consolidated Statements of Income for the Years Ended
December 31, 1997, 1996 and 1995 ...........................................................S-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1997, 1996 and 1995 ...............................................S-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995 ...........................................................S-5
Notes to Consolidated Financial Statements for the Years
Ended December 31, 1997, 1996 and 1995 .....................................................S-7
2. Consolidated Financial Statement Schedules:
</TABLE>
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> <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 (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> 33
<TABLE>
<S> <C> <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 10.15)
(Previously filed as an exhibit to the Company's S-1 Registration Statement
(Registration No. 33-52436)).
10.16 Indenture dated May 2, 1996 between Benton Oil and Gas Company and First Trust of New
York, National Association, Trustee related to $125,000,000, 11 5/8% Senior Notes Due
2003 (Incorporated by reference to Exhibit 4.1 to the Company's S-4 Registration
Statement filed June 17, 1996, SEC Registration No. 333-06125).
10.17 Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of
New York, National Association, Trustee related to an aggregate of $115,000,000
principal amount of 9 3/8% Senior Notes due 2007 (Incorporated by reference to Exhibit
10.1 to the Company's Form 10-Q for the quarter ended September 30, 1997).
21.1 List of subsidiaries.
23.1 Consent of Deloitte & Touche LLP.
23.2 Consent of Huddleston & Co., Inc.
27.1 Financial Data Schedule.
<FN>
- ---------------------------
(b) Reports on Form 8-K
No Form 8-K was filed during the last quarter of the registrant's fiscal year.
</FN>
</TABLE>
<PAGE> 34
INDEPENDENT AUDITORS' REPORT
- ----------------------------
Board of Directors and Stockholders
Benton Oil and Gas Company
Carpinteria, California
We have audited the accompanying consolidated balance sheets of Benton Oil and
Gas Company and subsidiaries as of December 31, 1997 and 1996, and the related
consolidated statements of income, stockholders' equity, and cash flows for each
of the three years in the period ended December 31, 1997. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Benton Oil and Gas Company and
subsidiaries at December 31, 1997 and 1996, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1997 in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Los Angeles, California
March 24, 1998
<PAGE> 35
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
---------------------------
(in thousands)
<TABLE>
<CAPTION>
DECEMBER
-----------------------
1997 1996
--------- ---------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 11,940 $ 32,432
Restricted cash 48 4,500
Marketable securities 156,436 52,004
Accounts receivable:
Accrued oil and gas revenue 45,379 50,137
Joint interest and other 8,029 9,860
Prepaid expenses and other 2,463 1,591
--------- ---------
TOTAL CURRENT ASSETS 224,295 150,524
RESTRICTED CASH 74,288 68,000
OTHER ASSETS 12,497 6,186
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of
$31,588 and $25,987 excluded from
amortization in 1997 and 1996, respectively) 367,756 259,622
Furniture and fixtures 5,734 4,283
--------- ---------
373,490 263,905
Accumulated depletion and depreciation (100,293) (52,870)
--------- ---------
273,197 211,035
--------- ---------
$ 584,277 $ 435,745
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade and other $ 43,490 $ 43,594
Accrued interest payable 5,533 3,776
Payroll and related taxes 1,799 1,862
Income taxes payable 4,535 889
Short term borrowings 1,530 853
Current portion of long term debt 1,463 1,133
--------- ---------
TOTAL CURRENT LIABILITIES 58,350 52,107
DEFERRED INCOME TAXES 24,811 16,679
LONG TERM DEBT 280,016 175,028
MINORITY INTEREST 23,368 17,032
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, par value $0.01 a share;
Authorized 5,000 shares; outstanding, none
Common stock, par value $0.01 a share;
Authorized 40,000 shares; issued 29,522 and 28,898
shares at December 31, 1997 and 1996, respectively 295 289
Additional paid-in capital 146,125 140,648
Retained earnings 52,011 33,962
Treasury stock, at cost, 50 shares in 1997 (699) -
--------- ---------
TOTAL STOCKHOLDERS' EQUITY 197,732 174,899
--------- ---------
$ 584,277 $ 435,745
========= =========
</TABLE>
See notes to consolidated financial statements
S-2
<PAGE> 36
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
---------------------------------
(in thousands, except per share data)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
REVENUES
Oil and gas sales $163,957 $147,703 $ 62,157
Gain on sale of properties 7,175
Net gain on exchange rates 2,285 2,820 998
Investment earnings and other 12,777 7,368 1,913
-------- -------- --------
179,019 165,066 65,068
-------- -------- --------
EXPENSES
Lease operating costs and production taxes 41,887 24,518 10,703
Depletion, depreciation and amortization 47,592 34,525 17,411
General and administrative 23,436 18,906 9,411
Interest 24,245 16,128 7,497
Partnership exchange expenses 2,140
Litigation settlement expenses 1,673
-------- -------- --------
137,160 96,217 46,695
-------- -------- --------
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST 41,859 68,849 18,373
INCOME TAXES 17,477 20,508 2,478
-------- -------- --------
INCOME BEFORE MINORITY INTEREST 24,382 48,341 15,895
MINORITY INTEREST 6,333 9,984 5,304
-------- -------- --------
INCOME BEFORE EXTRAORDINARY CHARGE 18,049 38,357 10,591
EXTRAORDINARY CHARGE FOR EARLY RETIREMENT OF
DEBT, NET OF TAX BENEFIT OF $879 10,075
-------- -------- --------
NET INCOME $ 18,049 $ 28,282 $ 10,591
======== ======== ========
NET INCOME PER COMMON SHARE:
Basic:
Income before extraordinary charge $ 0.62 $ 1.42 $ 0.42
Extraordinary charge - 0.38 -
-------- -------- --------
Net Income $ 0.62 $ 1.04 $ 0.42
======== ======== ========
Diluted:
Income before extraordinary charge $ 0.59 $ 1.29 $ 0.40
Extraordinary charge - 0.34 -
-------- -------- --------
Net Income $ 0.59 $ 0.95 $ 0.40
======== ======== ========
</TABLE>
See notes to consolidated financial statements.
S-3
<PAGE> 37
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-----------------------------------------------
(in thousands)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
COMMON ADDITIONAL RETAINED
SHARES COMMON PAID-IN EARNINGS TREASURY TOTAL
ISSUED STOCK CAPITAL (DEFICIT) STOCK
---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT JANUARY 1, 1995 24,900 $ 249 $ 92,921 $ (4,911) $ 88,259
Issuance of common shares:
Exercise of warrants 3 29 29
Exercise of stock options 273 3 1,335 1,338
Conversion of notes and
debentures 333 3 3,507 3,510
Securities registration costs (46) (46)
Net income 10,591 10,591
--------- --------- --------- --------- ---------
BALANCE AT DECEMBER 31, 1995 25,509 255 97,746 5,680 103,681
Issuance of common shares:
Exercise of warrants 994 10 12,134 12,144
Exercise of stock options 888 9 5,941 5,950
Conversion of notes and
debentures 711 7 6,870 6,877
Acquisitions 796 8 18,574 18,582
Securities registration costs (617) (617)
Net income 28,282 28,282
--------- --------- --------- --------- ----------
BALANCE AT DECEMBER 31, 1996 28,898 289 140,648 33,962 174,899
Issuance of common shares:
Exercise of warrants 343 3 3,524 3,527
Exercise of stock options 281 3 1,953 1,956
Treasury stock (50 shares) (699) (699)
Net income 18,049 18,049
--------- --------- --------- --------- --------- ---------
BALANCE AT DECEMBER 31, 1997 29,522 $ 295 $ 146,125 $ 52,011 $ (699) $ 197,732
========= ========= ========= ========= ========= =========
</TABLE>
See notes to consolidated financial statements.
S-4
<PAGE> 38
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
(in thousands)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 18,049 $ 28,282 $ 10,591
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization 47,592 34,525 17,411
Net earnings from limited partnerships (58)
Amortization of financing costs 1,390 670 185
(Gain) loss on disposition of assets 11 (6,950) 16
Partnership exchange expenses 2,140
Minority interest in undistributed earnings of subsidiary 6,336 9,984 5,304
Extraordinary charge for early retirement of debt 10,075
Deferred income taxes 8,132 16,679
Changes in operating assets and liabilities:
Accounts receivable 6,589 (35,180) (12,882)
Prepaid expenses and other (872) (1,377) 349
Accounts payable 1,381 21,328 9,905
Accrued interest payable 1,757 2,915 189
Payroll and related taxes (63) 1,036 300
Income taxes payable 3,646 725 1,039
--------- --------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES 93,948 84,852 32,349
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and equipment 34,638 15,408
Additions of property and equipment (109,760) (95,497) (68,288)
Increase in restricted cash (13,436) (74,050) (1,864)
Decrease in restricted cash 11,600 21,864 1,100
Purchases of marketable securities (291,943) (133,296)
Maturities of marketable securities 187,511 81,292
Distributions from limited partnerships 277
--------- --------- ---------
NET CASH USED IN INVESTING ACTIVITIES (216,028) (164,772) (53,644)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from exercise of stock options and warrants 5,483 17,818 1,320
Purchase of treasury stock (699)
Proceeds from issuance of short term borrowings and notes payable 116,190 181,921 24,557
Payments on short term borrowings and notes payable (11,680) (76,469) (11,999)
Prepayment premiums on debt retirement (10,632)
Increase in other assets (7,706) (6,466) (596)
--------- --------- ---------
NET CASH PROVIDED BY FINANCING ACTIVITIES 101,588 106,172 13,282
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(20,492) 26,252 (8,013)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 32,432 6,180 14,193
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 11,940 $ 32,432 $ 6,180
========= ========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for interest expense $ 20,860 $ 13,519 $ 7,012
========= ========= =========
Cash paid during the year for income taxes $ 4,589 $ 3,287 $ 1,885
========= ========= =========
</TABLE>
See notes to consolidated financial statements.
S-5
<PAGE> 39
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the year ended December 31, 1997, certain trade payables of GEOILBENT
were converted to long term debt. The Company's proportionate share of the
converted payables is $1,485,000.
During the year ended December 31, 1996, the Company acquired Crestone Energy
Corporation ("Crestone"), a privately held corporation headquartered in Denver,
Colorado, for 628,142 shares of common stock and options to purchase 107,571
shares of the Company's common stock at $7.00 per share, valued at $14.6
million.
During the year ended December 31, 1996, $3,226,000 principal amount of the
Company's 8% convertible notes and $4,310,000 principal amount of the Company's
8% convertible debentures were retired upon conversion into 275,081 and 435,872
shares of the Company's common stock, respectively.
During the year ended December 31, 1996, the Company financed the purchase of
oil and gas equipment and services in the amount of $273,000. Also during the
year ended December 31, 1996, the Company acquired the partners' interests in
each of the three limited partnerships sponsored by the Company in exchange for
an aggregate of 168,362 shares of the Company's common stock and warrants to
purchase 587,783 shares of common stock at $11.00 per share, with a total value
of $3,997,000.
During the year ended December 31, 1995, $1,393,000 of the Company's 8%
convertible notes and $2,118,000 of the Company's 8% convertible debentures were
retired in exchange for 118,785 and 214,237 shares of the Company's common
stock, respectively.
During the year ended December 31, 1995, the Company financed the purchase of
oil and gas equipment and services in the amount of $10,385,000 and leased
office equipment in the amount of $54,000. Also during 1995, the Company
acquired residential real estate for $1,725,000 in exchange for accounts and
notes receivable from an officer of the Company totaling $1,181,000 resulting in
an account payable of $544,000 (see Note 15).
See notes to consolidated financial statements.
S-6
<PAGE> 40
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Benton Oil and Gas Company (the "Company") engages in the exploration,
development, production and management of oil and gas properties.
The Company and its former subsidiary, Benton Oil and Gas Company of Louisiana,
participated as the managing general partner of three oil and gas limited
partnerships formed during 1989 through 1991. Under the provisions of the
limited partnership agreements, the Company received compensation as stipulated
therein, and functioned as an agent for the partnerships to arrange for the
management, drilling, and operation of properties, and assumed customary
contingent liabilities for partnership obligations. In January 1996, the Company
acquired the limited partnership interests for an aggregate of 168,362 shares of
common stock and warrants to purchase 587,783 shares of common stock at $11 per
share, and liquidated the partnerships (see Note 2).
The consolidated financial statements include the accounts of the Company and
its subsidiaries. The Company's investments in limited partnerships and the
Russia joint venture ("GEOILBENT") are proportionately consolidated based on the
Company's ownership interest. GEOILBENT (owned 34% by the Company) has been
included in the consolidated financial statements based on a fiscal period
ending September 30. All material intercompany profits, transactions and
balances have been eliminated.
CASH AND CASH EQUIVALENTS
Cash equivalents include money market funds and short term certificates of
deposit with original maturity dates of less than three months.
MARKETABLE SECURITIES
Marketable securities are carried at amortized cost. The marketable securities
the Company may purchase are limited to those defined as Cash Equivalents in the
indentures for its senior unsecured notes. Cash Equivalents may be comprised of
high-grade debt instruments, demand or time deposits, bankers' acceptances and
certificates of deposit or acceptances of large U.S. financial institutions and
commercial paper of highly rated U.S. corporations; all having maturities of no
more than 180 days. The Company's marketable securities at cost, which
approximates fair value at December 31, 1997, consisted of $12.6 million in
government backed notes, $139.4 million in commercial paper, $2.4 million in
agreements to repurchase treasury securities and $2.0 million in bankers'
acceptances and at December 31, 1996, consisted of $26.2 million in treasury
securities and agreements to repurchase treasury securities, $19.8 million in
commercial paper and $6.0 million in bankers' acceptances.
ACCOUNTS RECEIVABLE
The Company has recorded an allowance for doubtful accounts of $367,000 and
$336,000 related to other accounts receivable at December 31, 1997 and 1996,
respectively.
OTHER ASSETS
Other assets consist principally of costs associated with the issuance of long
term debt. Debt issuance costs are amortized on a straight-line basis over the
life of the debt.
S-7
<PAGE> 41
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for oil and gas
properties. Accordingly, all costs associated with the acquisition, exploration,
and development of oil and gas reserves are capitalized as incurred, including
exploration overhead of $1,894,000, $1,441,000 and $2,282,000 for the years
ended December 31, 1997, 1996 and 1995, respectively. Only overhead which is
directly identified with acquisition, exploration or development activities is
capitalized. All costs related to production, general corporate overhead and
similar activities are expensed as incurred. The costs of oil and gas properties
are accumulated in cost centers on a country by country basis, subject to a cost
center ceiling (as defined by the Securities and Exchange Commission).
All capitalized costs of oil and gas properties (excluding unevaluated property
acquisition and exploration costs) and the estimated future costs of developing
proved reserves, are depleted over the estimated useful lives of the properties
by application of the unit-of-production method using only proved oil and gas
reserves. Depletion expense attributable to the Venezuelan cost center for the
years ended December 31, 1997, 1996 and 1995 was $43,584,000, $29,523,000 and
$11,393,000 ($2.83, $2.33 and $2.09 per equivalent barrel), respectively.
Depletion expense attributable to the Russian cost center for the years ended
December 31, 1997, 1996 and 1995 was $3,079,000, $2,747,000 and $1,512,000
($3.50, $3.59 and $3.08 per equivalent barrel), respectively. Depletion expense
attributable to the United States cost center for the years ended December 31,
1996 and 1995 was $1,705,000 and $4,187,000 ($6.55 and $5.98 per equivalent
barrel), respectively. Depreciation of furniture and fixtures is computed using
the straight-line method, with depreciation rates based upon the estimated
useful life applied to the cost of each class of property. Depreciation expense
was $879,000, $548,000 and $310,000 for the years ended December 31, 1997, 1996
and 1995, respectively.
TAXES ON INCOME
Deferred income taxes reflect the net tax effects, calculated at currently
enacted rates, of (a) future deductible/taxable amounts attributable to events
that have been recognized on a cumulative basis in the financial statements or
income tax returns and (b) operating loss and tax credit carryforwards. A
valuation allowance is recorded, if necessary, to reduce net deferred income tax
assets to the amount expected to be recoverable.
FOREIGN CURRENCY
The Company has significant operations outside of the United States, principally
in Russia and Venezuela. Both Russia and Venezuela are considered highly
inflationary economies and, as a result, operations in those countries are
remeasured in United States dollars and any currency gains or losses are
recorded in the statement of income. The Company attempts to manage its
operations in a manner to reduce its exposure to foreign exchange losses;
however, there are many factors which affect foreign exchange rates and
resulting exchange gains and losses, many of which are beyond the influence of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the United States dollar. It is not possible to predict
the extent to which the Company may be affected by future changes in exchange
rates.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist primarily of cash and cash
equivalents, accounts receivable and payable, marketable securities, short term
borrowings and long term debt. The book values of all financial instruments,
other than long term debt, are representative of their fair values due to their
short term maturities. The carrying values of the Company's long term debt,
except for the senior unsecured notes, are considered to approximate their fair
values because their interest rates are comparable to current rates available to
the company. The aggregate fair value of the Company's senior unsecured notes,
based on the last trading prices at December 31, 1997, was approximately $246.7
million (carrying value of $230.0 million).
S-8
<PAGE> 42
TREASURY STOCK
In June 1997, the Board of Directors instituted a treasury stock repurchase
program under which the Company is authorized to purchase up to 1,500,000 shares
of its common stock. The shares will be used for re-issuance in connection with
the Company's employee stock option plan, treasury stock or for other corporate
purposes to be determined in the future. During 1997, the Company repurchased
50,000 shares at an average price of $13.99 per share.
STOCK OPTIONS
Statement of Financial Accounting Standards No. 123 ("SFAS 123") requires
expanded disclosures of stock-based compensation arrangements and encourages
(but does not require) compensation cost to be measured based on the fair value
of the equity instrument awarded. The Company continues to apply APB Opinion No.
25 ("APB 25") to its stock based compensation awards to employees and discloses
the required pro forma effect on net income and earnings per share (see Note 7).
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain items in 1996 and 1995 have been reclassified to conform to the 1997
financial statement presentation.
NOTE 2 - ACQUISITIONS AND SALES
In March 1995, the Company sold its 32.5% working interest in certain depths
(above approximately 10,575 feet) in the West Cote Blanche Bay Field for an
adjusted sales price of approximately $14.9 million. In April 1996, the Company
sold its remaining interests in the West Cote Blanche Bay, Rabbit Island and
Belle Isle Fields located in the Gulf Coast of Louisiana for approximately $35.4
million, resulting in a gain of approximately $7.2 million after adjustments for
revenues and expenses subsequent to the effective date of December 31, 1995 and
satisfaction of a net profits interest associated with the properties. In
conjunction with this sale and to obtain the required consents for such sale,
the Company agreed to repay $35 million in senior unsecured notes and a $5
million revolving credit facility which was secured in part by these properties.
Debt prepayment premiums and related costs totaling approximately $11.0 million
($10.1 million net of tax benefits) were recognized as an extraordinary charge
in 1996.
In January 1996, the Company completed an exchange offer under which it issued
an aggregate of 168,362 shares of common stock and warrants to purchase 587,783
shares of common stock at $11 per share in exchange for all outstanding limited
partnership interests in the three remaining limited partnerships sponsored by
the Company. The shares of common stock were valued at $1.9 million (based upon
the current market price at the time of the offer), which was allocated to oil
and gas properties. Substantially all of the oil and gas properties were
immediately sold at their approximate book value. The warrants, issued as an
inducement to the participants to accept the exchange offer, were valued at
$3.64 per warrant (an aggregate of $2.1 million), which was charged to expense
in 1996.
S-9
<PAGE> 43
NOTE 3 - LONG TERM DEBT
Long term debt consists of the following at December 31 (in thousands):
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
Senior unsecured notes with interest at 9.375%
See description below $105,000
Senior unsecured notes with interest at 11.625%
See description below 125,000 $125,000
Benton-Vinccler credit facility with interest at
LIBOR plus 6.125%. Collateralized by a time deposit
of the Company earning approximately LIBOR plus 5.75%
See description below 50,000 50,000
Other 1,479 1,161
-------- --------
281,479 176,161
Less current portion 1,463 1,133
-------- --------
$280,016 $175,028
======== ========
</TABLE>
In November 1997, the Company issued $115 million in 9.375% senior unsecured
notes due November 1, 2007.The Company subsequently repurchased $10 million of
the notes at their par value. Interest on the notes is due May 1 and November 1
of each year, beginning May 1, 1998. The indenture agreement provides for
certain limitations on liens, additional indebtedness, certain investment and
capital expenditures, dividends, mergers and sales of assets. At December 31,
1997, the Company was in compliance with all covenants of the indenture. The
proceeds will be used for general corporate purposes, including the Company's
ongoing exploration and development programs.
In May 1996, the Company issued $125 million in 11.625% senior unsecured notes
due May 1, 2003. Interest on the notes is due May 1 and November 1 of each year.
The indenture agreement provides for certain limitations on liens, additional
indebtedness, certain investment and capital expenditures, dividends, mergers
and sales of assets. At December 31, 1997, the Company was in compliance with
all covenants of the indenture.
In August 1996, Benton-Vinccler entered into a $50 million, long term credit
facility with Morgan Guaranty Trust Company of New York ("Morgan Guaranty") to
repay the balance outstanding under a short term credit facility and to repay
certain advances received from the Company. The credit facility is
collateralized in full by a time deposit of the Company and bears interest at
LIBOR plus 6.125% (11.844% at December 31, 1997) and matures in August 1999. The
Company will receive interest on its time deposit and a security fee on the
outstanding principal of the loan, for a combined total of approximately LIBOR
plus 5.75%. The loan arrangement contains no restrictive covenants and no
financial ratio covenants.
The principal payment requirements for the long term debt outstanding at
December 31, 1997 are as follows for the years ending December 31 (in
thousands):
<TABLE>
<S> <C> <C>
1998 $ 1,463
1999 50,013
2000 3
2001 -
2002 -
Subsequent Years 230,000
--------
$281,479
========
</TABLE>
S-10
<PAGE> 44
NOTE 4 - SHORT TERM BORROWINGS
GEOILBENT has periodically received production payment advances against future
oil shipments from export marketers. The advances are repaid through
withholdings from oil sales on a monthly basis and bear interest at market
rates. At December 31, 1997 and 1996, no amounts were outstanding under such
production payment advances. GEOILBENT also entered into an agreement with
Morgan Guaranty for a short term credit facility under which the Company
provides cash collateral for the loans to GEOILBENT. At December 31, 1997 and
1996, the Company's proportionate share of the outstanding short term borrowings
of GEOILBENT was $1.5 million and $0.9 million, respectively.
NOTE 5 - COMMITMENTS AND CONTINGENCIES
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of the West Cote Blanche Bay Properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that at the time of
Tesla's acquisition, it was insolvent and that it paid a price in excess of the
fair value of the property. The Company intends to vigorously contest the suit
and in its management's opinion, while it is unlikely that the suit will result
in a material adverse effect on the Company's financial statements, it is too
early to assess the probability of such an outcome.
In the normal course of its business, the Company may periodically become
subject to actions threatened or brought by its investors or partners in
connection with the operation or development of its properties or the sale of
securities. Prior to 1992, the Company was engaged in the formation and
operation of oil and gas limited partnership interests. In 1992, the Company
ceased raising funds through such sales. Certain limited partners in limited
partnerships sponsored by the Company have brought an action against the Company
in connection with the Company's operation of the limited partnerships as
managing general partner. The plaintiffs seek actual and punitive damages for
alleged actions and omissions by the Company in operating the partnerships and
alleged misrepresentations made by the Company in selling the limited
partnership interests. In May 1995, the Company agreed to a binding arbitration
proceeding with respect to such claims. In April 1997, the plaintiffs commenced
discovery. The Company intends to vigorously defend this action and does not
believe the claims raised are meritorious. However, new developments could alter
this conclusion at any time. The Company will be forced to expend time and
financial resources to defend or resolve any such matters. The Company is also
subject to ordinary litigation that is incidental to its business. None of the
above matters are expected to have a material adverse effect on the Company's
financial statements.
In May 1996, the Company entered into an agreement with Morgan Guaranty which
provides for an $18 million cash collateralized 5-year letter of credit to
secure the Company's performance of the minimum exploration work program
required in the Delta Centro Block in Venezuela.
Investors in partnerships which were sponsored by a third party have sued the
Company on the theory that since it provided oil and gas drilling prospects to
those partnerships and operated substantially all of their properties, it was
responsible for alleged violations of securities laws in connection with the
offer and sale of interests, contractual breach of fiduciary duty and fraud. The
Company entered into a settlement agreement related to these claims, whereby the
Company paid $990,000 to the plaintiffs in full settlement of these claims.
Legal fees of $683,000 in addition to the settlement amount were included in
litigation settlement expenses for the year ended December 31, 1995.
The Company has entered into a 15 year lease agreement for office space
currently under construction in Carpinteria, California. It is anticipated that
the building will be ready for occupancy in late 1998. The Company will lease
the entire building (50,000 square feet) for $72,500 per month, subject to
adjustments for tenant improvements, with annual rent adjustments based on
certain changes in the Consumer Price Index. The Company intends to sublet a
portion of the building which would not be immediately needed for operations.
S-11
<PAGE> 45
The Company's aggregate rental commitments for noncancellable agreements at
December 31, 1997, are as follows (in thousands):
<TABLE>
<CAPTION>
Rental Commitments Sub-Lease
------------------ ---------
<S> <C> <C> <C>
1998 $ 719 $ -
1999 1,277 337
2000 1,208 337
2001 1,190 337
2002 1,179 337
Thereafter 10,187 675
------- -------
$15,760 $ 2,023
======= =======
</TABLE>
Rental expense was $2,037,000, $2,233,000 and $1,981,000 for the years ended
December 31, 1997, 1996 and 1995, respectively.
NOTE 6 - TAXES ON INCOME
The tax effects of significant items comprising the Company's net deferred
income taxes as of December 31, 1997 and 1996 are as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
Deferred tax assets:
Operating loss carryforwards $ 24,529 $ 20,970
Other 338 720
Valuation allowance (13,841) (14,498)
-------- --------
Total 11,026 7,192
-------- --------
Deferred tax liabilities:
Difference in basis of property (35,837) (23,871)
-------- --------
Net deferred tax liability $(24,811) $(16,679)
======== ========
</TABLE>
The components of income before income taxes and minority interest are as
follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
Income (loss) before income taxes:
<S> <C> <C> <C>
United States $ (5,989) $ 3,063 $ (9,500)
Foreign 47,848 65,787 27,873
-------- -------- --------
Total $ 41,859 $ 68,850 $ 18,373
======== ======== ========
</TABLE>
The provision for income taxes consisted of the following at December 31, (in
thousands):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Current:
United States $ 4,617 $ 2,282 $ 919
Foreign 4,728 1,547 1,559
-------- -------- --------
9,345 3,829 2,478
-------- -------- --------
Deferred:
United States (3,573) - -
Foreign 11,705 16,679 -
-------- -------- --------
8,132 16,679 -
-------- -------- --------
$ 17,477 $ 20,508 $ 2,478
======== ======== ========
</TABLE>
S-12
<PAGE> 46
A comparison of the income tax expense at the federal statutory rate to the
Company's provision for income taxes is as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Computed tax expense at the statutory rate $ 14,651 $ 24,097 $ 6,431
State income taxes, net of federal effect 1,072 1,249 919
Rate differential for foreign income (314) (4,800) (7,278)
Change in valuation allowance and other 2,068 (38) 2,406
-------- -------- --------
Provision for income taxes $ 17,477 $ 20,508 $ 2,478
======== ======== ========
</TABLE>
At December 31, 1997, the Company had, for federal income tax purposes,
operating loss carryforwards of approximately $63 million, expiring in the years
2003 through 2012. If the carryforwards are ultimately realized, approximately
$13 million will be credited to additional paid-in capital for tax benefits
associated with deductions for income tax purposes related to stock options.
The Company has not provided for United States income taxes on $93 million of
foreign subsidiaries' unremitted earnings at December 31, 1997 which are
expected to be reinvested indefinitely. It is not practicable to determine the
amount of income taxes that might be payable if such earnings are ultimately
repatriated.
NOTE 7 - STOCK OPTIONS
The Company adopted its 1988 Stock Option Plan in December 1988 authorizing
options to acquire up to 418,824 shares of common stock. Under the plan,
incentive stock options ("ISOs") were granted to a key employee and other
non-qualified stock options ("NQSOs"), stock or bonus rights were granted to
other key employees, directors, independent contractors and consultants at
prices equal to or below market price, exercisable over various periods. The
remaining options to purchase 80,000 shares of common stock for $4.89 per share
were exercised during 1995. During 1989, the Company adopted its 1989
Nonstatutory Stock Option Plan covering 2,000,000 shares of common stock which
were granted to key employees, directors, independent contractors and
consultants at prices equal to or below market prices, exercisable over various
periods. The plan was amended during 1990 to add 1,960,000 shares of common
stock to the plan.
In September 1991, the Company adopted the 1991-1992 Stock Option Plan and the
Directors' Stock Option Plan. The 1991-1992 Stock Option Plan, as amended in
1996 and 1997, permits the granting of stock options to purchase up to 4,800,000
shares of the Company's common stock in the form of ISOs and NQSOs to officers
and employees of the Company. Options may be granted as ISOs, NQSOs or a
combination of each, with exercise prices not less than the fair market value of
the common stock on the date of the grant. The amount of ISOs that may be
granted to any one participant is subject to the dollar limitations imposed by
the Internal Revenue Code of 1986, as amended. In the event of a change in
control of the Company, all outstanding options become immediately exercisable
to the extent permitted by the 1991-1992 Stock Option Plan. All options granted
to date under the 1991-1992 Stock Option Plan vest ratably over a three-year
period from their dates of grant and expire ten years from grant date or one
year after retirement, if earlier.
The Directors' Stock Option Plan permits the granting of nonqualified stock
options ("Director NQSOs") to purchase up to 400,000 shares of common stock to
nonemployee directors of the Company. Upon election as a director and annually
thereafter, each individual who serves as a nonemployee director automatically
is granted an option to purchase 10,000 shares of common stock at a price not
less than the fair market value of common stock on the date of grant. All
Director NQSOs vest automatically on the date of the grant of the options and at
December 31, 1997, options to purchase 250,000 shares of common stock were both
outstanding and exercisable.
A summary of the status of the Company's stock option plans as of December 31,
1997, 1996 and 1995 and changes during the years ending on those dates is
presented below (shares in thousands):
S-13
<PAGE> 47
<TABLE>
<CAPTION>
1997 1996 1995
------------------- ------------------- -------------------
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 year: $10.78 3,037 $ 8.04 3,342 $ 6.74 3,034
Options granted 14.32 889 19.33 658 13.86 558
Options exercised 6.61 (224) 6.69 (886) 4.92 (193)
Options canceled 14.41 (139) 12.14 (77) 6.53 (57)
------ ------ ------
Outstanding at end of the year 11.78 3,563 10.78 3,037 8.04 3,342
====== ====== ======
Exercisable at end of the year 9.43 2,206 7.90 1,887 6.76 2,209
====== ====== ======
</TABLE>
Significant option groups outstanding at December 31, 1997 and related weighted
average price and life information follow (shares in thousands):
<TABLE>
<CAPTION>
RANGE OF NUMBER OUTSTANDING WEIGHTED-AVERAGE WEIGHTED- NUMBER WEIGHTED-
EXERCISE AT REMAINING AVERAGE EXERCISE EXERCISABLE AT AVERAGE
PRICES DECEMBER 31, 1997 CONTRACTUAL LIFE PRICE DECEMBER 31, 1997 EXERCISE PRICE
------ ------------------- ------------------- ---------------- ----------------- --------------
<S> <C> <C> <C> <C> <C> <C>
$ 2.39 52 2.2 Years $ 2.39 52 $ 2.39
4.89 - 7.00 765 4.4 Years 5.52 765 5.52
7.50 - 10.88 880 5.2 Years 8.86 869 8.85
11.50 - 16.50 1,269 9.0 Years 13.74 328 14.35
17.38 - 24.13 597 9.1 Years 20.76 192 21.10
------ -----
3,563 2,206
====== =====
</TABLE>
The weighted average fair value of the stock options granted from the 1991-1992
Stock Option Plan and the Directors' Stock Option Plan during 1997, 1996 and
1995 was $9.83, $13.10, $8.92 respectively. The fair value of each stock option
grant is estimated on the date of grant using the Black-Scholes option pricing
model with the following weighted average assumptions used:
<TABLE>
<CAPTION>
1997 1996 1995
---------- --------- -------
<S> <C> <C> <C>
Expected life 9.0 years 8.6 years 7.5 years
Risk-free interest rate 6.0% 6.2% 6.0%
Volatility 54% 54% 54%
Dividend yield 0% 0% 0%
</TABLE>
The Company accounts for stock-based compensation in accordance with APB 25,
under which no compensation cost has been recognized for stock option awards.
Had compensation cost for the plans been determined consistent with SFAS 123,
the Company's pro forma net income and earnings per share for 1997, 1996 and
1995 would have been as follows (in thousands, except per share data):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
Net income:
<S> <C> <C> <C>
Income before extraordinary charge $13,343 $36,083 $10,369
Extraordinary charge - 10,075 -
------- ------- -------
Net income $13,343 $26,008 $10,369
======= ======= =======
Net income per common share:
Basic:
Income before extraordinary charge $ 0.46 $ 1.33 $ 0.41
Extraordinary charge - 0.37 -
------- ------- -------
Net income $ 0.46 $ 0.96 $ 0.41
======== ========= =========
Diluted:
Income before extraordinary charge $ 0.44 $ 1.22 $ 0.39
Extraordinary charge - 0.34 -
------- ------- -------
Net income $ 0.44 $ 0.88 $ 0.39
======== ========= =========
</TABLE>
S-14
<PAGE> 48
In connection with the acquisition of Crestone by the Company in December 1996,
the Company adopted the Crestone Energy Corporation 1996 Stock Option Plan.
Under the plan, Crestone is authorized to issue up to 107,571 options to
purchase the Company's common stock for $7.00 per share. The plan was adopted in
substitution of Crestone's stock option plan and all options to purchase shares
of Crestone common stock were replaced, under the plan, by options to purchase
shares of the Company's common stock. All options were issued upon the
acquisition of Crestone and vested upon issuance. At December 31, 1997, options
to purchase 98,713 shares of common stock were both outstanding and exercisable.
In addition to options issued pursuant to the plans, options for 10,000 and
15,000 shares of common stock were issued in 1997 and 1995, respectively, to
individuals other than officers, directors or employees of the Company at prices
ranging from $10.88 to $11.88 which vest over three to four years. At December
31, 1997, a total of 208,500 options issued outside the plans were outstanding,
183,500 of which were vested.
NOTE 8 - STOCK WARRANTS
During the years ended December 31, 1996 and 1995, the Company issued a total of
587,783 and 125,000 warrants, respectively. Each warrant entitles the holder to
purchase one share of common stock at the exercise price of the warrant.
Substantially all the warrants are immediately exercisable upon issuance.
In July 1994, the Company issued warrants entitling the holder to purchase a
total of 150,000 shares of common stock at $7.50 per share, subject to
adjustment in certain circumstances, that are exercisable on or before July
2004. 50,000 warrants were immediately exercisable, and 50,000 warrants became
exercisable each July in 1995 and 1996. During the year ended December 31, 1996,
142,000 of these warrants were exercised. In September 1994, 250,000 warrants
were issued in connection with the issuance of $15 million in senior unsecured
notes, and in December 1994, 50,000 warrants were issued in connection with a
revolving secured credit facility.
In June 1995, 125,000 warrants were issued in connection with the issuance of
$20 million in senior unsecured notes.
In January 1996, 587,783 warrants were issued in connection with an exchange
offer under which the Company acquired the outstanding limited partnership
interests in three limited partnerships sponsored by the Company (see Note 2).
During the years ended December 31, 1997 and 1996, 1,578 and 9,215,
respectively, of the warrants were exercised.
The dates the warrants were issued, the expiration dates, the exercise prices
and the number of warrants issued and outstanding at December 31, 1997 were
(shares in thousands):
<TABLE>
<CAPTION>
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
July 1994 July 2004 $ 7.50 150 8
250
September 1994 September 2002 9.00 250
50
December 1994 December 2004 12.00 50
125
June 1995 June 2007 17.09 125
January 1996 January 1999 11.00 588 577
----- -----
1,163 1,010
===== =====
</TABLE>
NOTE 9 - RUSSIAN OPERATIONS
The European Bank for Reconstruction and Development ("EBRD") and International
Moscow Bank ("IMB") have agreed to lend a total of $65 million to GEOILBENT
(owned 34% by the Company) under parallel reserve-based, non-recourse loan
agreements ("GEOILBENT Credit Facility"). Initial funding of $10.2 million and
$1.8 million occurred in October 1997 and January 1998. The proceeds from the
loans will be used by GEOILBENT to develop the North Gubkinskoye and
Prisklonovoye fields in West Siberia, Russia. Additional borrowings will be
based on achieving certain reserve and production milestones. The Company's
share of the borrowings are not included in the accompanying financial
statements because they occurred subsequent to September 30, 1997, the end of
the fiscal period for GEOILBENT.
S-15
<PAGE> 49
For the period January 1 through June 30, 1996, the Company recorded an expense
for the Russian export tariff of $845,000. GEOILBENT received a waiver from the
export tariff for 1995 and in July 1996, such oil export tariffs were terminated
in conjunction with a loan agreement with the International Monetary Fund.
Excise, pipeline and other taxes continue to be levied on all oil producers and
certain exporters. Although the Russian regulatory environment has become less
volatile, the Company is unable to predict the impact of taxes, duties and other
burdens for the future.
NOTE 10 - VENEZUELA OPERATIONS
On July 31, 1992, the Company and its partner, Venezolana de Inversiones y
Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement
to reactivate and further develop three Venezuelan oil fields with Lagoven,
S.A., then one of three exploration and production affiliates of the national
oil company, Petroleos de Venezuela, S.A ("PDVSA") which have subsequently all
been combined into PDVSA Petroleo y Gas, S.A. ("P&G"). The operating service
agreement covers the Uracoa, Bombal and Tucupita fields that comprise the South
Monagas Unit ("Unit"). Under the terms of the operating service agreement,
Benton-Vinccler, C.A. ("Benton-Vinccler"), a corporation owned 80% by the
Company and 20% by Vinccler, is a contractor for P&G and is responsible for
overall operations of the Unit, including all necessary investments to
reactivate and develop the fields comprising the Unit. Benton-Vinccler receives
an operating fee in U.S. dollars deposited into a U.S. commercial bank account
for each barrel of crude oil produced (subject to periodic adjustments to
reflect changes in a special energy index of the U.S. Consumer Price Index) and
is reimbursed according to a prescribed formula in U.S. dollars for its capital
costs, provided that such operating fee and cost recovery fee cannot exceed the
maximum dollar amount per barrel set forth in the agreement (which amount is
periodically adjusted to reflect changes in the average of certain world crude
oil prices). The Venezuelan government maintains full ownership of all
hydrocarbons in the fields.
In January 1996, the Company and its bidding partners, Louisiana Land &
Exploration ("LL&E"), which was recently acquired by Burlington Resources, Inc.,
and Norcen Energy Resources, LTD ("Norcen"), recently acquired by Union Pacific
Resources Group Inc., were awarded the right to explore and develop the Delta
Centro Block in Venezuela. The contract requires a minimum exploration work
program consisting of completing a 839 kilometer seismic survey and drilling
three wells to depths of 12,000 to 18,000 feet within five years. PDVSA
estimates that this minimum exploration work program will cost $60 million and
requires that the Company, LL&E and Norcen each post a performance surety bond
or standby letter of credit for its pro rata share of the estimated work
commitment expenditures. The Company has a 30% interest in the exploration
venture, with LL&E and Norcen each owning a 35% interest. Under the terms of the
operating agreement, which establishes the management company of the project,
LL&E will be the operator of the field and, therefore, the Company will not be
able to exercise control of the operations of the venture. Corporacion
Venezolana del Petroleo, S.A., an affiliate of PDVSA, has the right to obtain a
35% interest in the management company, which dilutes the voting power of the
partners on a pro rata basis. In July 1996, formal agreements were finalized and
executed and the Company posted an $18 million standby letter of credit, which
is collateralized in full by a time deposit of the Company, to secure its 30%
share of the minimum exploration work program (see Note 5). As of December 31,
1997, the Company' share of expenditures to date was $4.0 million.
NOTE 11 - CHINA OPERATIONS
In December 1996, the Company acquired Crestone, a privately held corporation
headquartered in Denver, Colorado, for 628,142 shares of common stock and
options to purchase 107,571 shares of the Company's common stock at $7.00 per
share, valued at $14.6 million. Crestone's primary asset is a large undeveloped
acreage position in the South China Sea, under a petroleum contract with China
National Offshore Oil Corporation ("CNOOC") of the People's Republic of China
for an area known as Wan'An Bei, WAB-21. Crestone will, as a wholly owned
subsidiary of the Company, continue as the operator and contractor of WAB-21.
Crestone has submitted an exploration program and budget to CNOOC for 1997.
However, due to certain territorial disputes over the sovereignty of the
contract area, it is unclear when such program will commence.
In October 1997, the Company signed a farmout agreement with Shell Exploration
(China) Limited ("Shell") whereby the Company will acquire a 50% participation
interest in Shell's Liaohe area onshore exploration projection in northeast
China. Shell holds a petroleum contract with China National Petroleum
Corporation ("CNPC") to explore and develop
S-16
<PAGE> 50
the deep rights in the Qingshui Block, a 563 square kilometer area
(approximately 140,000 acres) in the delta of the Liaohe River. Shell will be
the operator of the project. The Company is required to pay to Shell 50% of
Shell's costs to date, estimated to be approximately $4.0 million ($2 million to
the Company) and to pay 100% of the first $8.0 million of the costs for the
phase one exploration period, after which, costs will be shared equally. If the
first phase of the exploration period results in a commercial discovery and if
the Company elects to continue to phase two, then the Company will pay 100% of
the first $8.0 million of the costs of the second phase of the exploration
period, after which, costs will be shared equally. The Company and Shell will
share costs equally for the third exploration phase. As of December 31, 1997,
the Company had incurred $0.2 million related to the farmout agreement.
NOTE 12 - SANTA BARBARA OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy. The project
area covers the Molino, the Gaviota and the Caliente fields, located
approximately 35 miles west of Santa Barbara, California. Molino Energy holds a
100% working interest in each of the leases. The Company serves as operator of
the project. In consideration of the 40% participation interest, the Company
will initially pay 100% of the costs of the first well to be drilled on the
block, which began in March 1998. The Company's cost participation in the first
well will be reduced to 53% when an amount equal to 70% of costs of $2.5 million
incurred by Molino Energy prior to the agreement with the Company is paid from
47% of the Company's initial cost participation. The Company will then pay 40%
of all subsequent costs. As of December 31, 1997, the Company had incurred $2.7
million related to the project.
NOTE 13 - JORDAN OPERATIONS
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's Natural Resources Authority to explore,
develop and produce the Sirhan block in southeastern Jordan. The Sirhan block
consists of approximately 1.2 million acres (4,827 square kilometers) and is
located in the Sirhan basin adjacent to the Saudi Arabia border. Under the terms
of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which is expected to last
approximately two years. If the Company ultimately elects to continue through
phases two and three, it would be obligated to spend an additional $18 million
over the succeeding six years. At December 31, 1997, the Company had incurred
$1.3 million related to the PSA.
NOTE 14 - SENEGAL OPERATIONS
In December 1997, the Company signed a memorandum of understanding with Societe
des Petroles du Senegal ("Petrosen"), the state oil company of the Republic of
Senegal, to receive a minimum 45% working interest in and to operate the
approximately one million acre onshore Thies Block in western Senegal. In
addition, the Company obtained exclusive rights from Petrosen to evaluate and
reprocess geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea Bissau border in the south, and to choose
certain blocks for further data acquisition and exploration drilling. The
Company's working interest in any offshore discovery will be 85% with the
remainder held by Petrosen.
The Company's $5.4 million work commitment on the Thies Block where Petrosen has
recently drilled and completed the Gadiaga #2 discovery well, consists of
hooking up the existing well, drilling two additional wells and constructing a
41 kilometer (approximately 25 mile) gas pipeline en route to Senegal's main
electric generating facility near Dakar.
NOTE 15 - RELATED PARTY TRANSACTIONS
In December 1995, the Company purchased a home from Mr. A. E. Benton, its Chief
Executive Officer, for $1.7 million, based on independent appraisals, and from
the proceeds Mr. Benton repaid the balance owed to the Company of $593,000 plus
accrued interest and a $300,000 loan guaranteed by the Company. During 1996 and
1997, the Company made loans to Mr. Benton, Mr. M.B. Wray, its Vice Chairman,
and Mr. J.M. Whipkey, its Chief Financial Officer, each loan bearing interest at
6%. At December 31, 1996, the balances owed to the Company by Mr. Benton and Mr.
Wray were $0.3 million and $0.6 million, respectively. At December 31, 1997, the
balances owed to the Company by Mr. Benton, Mr. Wray and Mr. Whipkey were $2.0
million, $0.7 million and $0.5 million, respectively.
S-17
<PAGE> 51
NOTE 16 - EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128 ("SFAS 128") "Earnings per Share." SFAS
128 replaces the presentation of primary earnings per share with a presentation
of basic earnings per share based upon the weighted average number of common
shares for the period. It also requires dual presentation of basic and diluted
earnings per share for companies with complex capital structures. SFAS 128 was
adopted by the Company in December 1997 and earnings per share for all prior
periods have been restated. The numerator (income) and denominator (shares) of
the basic and diluted earnings per share computations for income before
extraordinary charge were (in thousands, except per share amounts):
<TABLE>
<CAPTION>
INCOME SHARES AMOUNT PER SHARE
------ ------ ----------------
<S> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1997
BASIC EPS
Income available to common stockholders $18,049 29,119 $0.62
======= ====== =====
Effect of Dilutive Securities:
Stock options and warrants -- 1,715
------ -----
DILUTED EPS
Income available to common stockholders $18,049 30,834 $0.59
======= ====== =====
FOR THE YEAR ENDED DECEMBER 31, 1996
BASIC EPS
Income available to common stockholders $38,357 27,088 $1.42
======= ====== =====
Effect of Dilutive Securities:
Convertible notes and debentures 33 223
Stock options and warrants -- 2,502
------- ------ -----
DILUTED EPS
Income available to common stockholders
and assumed conversions $38,390 29,813 $1.29
======= ====== =====
FOR THE YEAR ENDED DECEMBER 31, 1995
BASIC EPS
Income available to common stockholders $10,591 25,084 $0.42
======= ====== =====
Effect of Dilutive Securities:
Stock options and warrants -- 1,589
------- ------
DILUTED EPS
Income available to common stockholders $10,591 26,673 $0.40
======= ====== =====
</TABLE>
For the years ended December 31, 1997, 1996 and 1995, 581,324, 135,579, and
117,562 options, respectively, were excluded from the earnings per share
calculations because they were anti-dilutive.
NOTE 17 - MAJOR CUSTOMERS
The Company is principally involved in the business of oil and gas exploration
and production. P&G was the only oil and gas purchaser which represented more
than 10% of the Company's oil and gas revenues during the years ended December
31, 1997, 1996 and 1995, representing 94%, 93% and 79%, respectively.
S-18
<PAGE> 52
NOTE 18 - OIL AND GAS ACTIVITIES
Total costs incurred in oil and gas acquisition, exploration and development
activities were (in thousands):
<TABLE>
<CAPTION>
UNITED STATES
AND
VENEZUELA RUSSIA CHINA OTHER TOTAL
--------- ------ ----- ----- -----
<S> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1997
Development costs $95,791 $ 2,652 $ 98,443
Exploration costs 3,919 33 $ 1,088 $ 5,718 10,758
------- ------- ------- -------- --------
$99,710 $ 2,685 $ 1,088 $ 5,718 $109,201
======= ======= ======= ======== ========
YEAR ENDED DECEMBER 31, 1996
Property acquisition costs $15,106 $ 1,139 $ 16,245
Development costs $82,197 $ 6,047 1,498 89,742
Exploration costs 1,393 279 715 2,387
------- ------- ------- -------- --------
$83,590 $ 6,047 $15,385 $ 3,352 $108,374
======= ======= ======= ======== ========
YEAR ENDED DECEMBER 31, 1995
Property acquisition costs $ 436 $ 436
------- ------- -------- --------
Development costs $ 54,533 $ 12,374 5,463 72,370
Exploration costs 112 593 705
------- ------- -------- --------
$ 54,645 $ 12,374 $6,492 $73,511
======== ======== ======== ========
</TABLE>
The Company's aggregate amount of capitalized costs related to oil and gas
producing activities consists of the following at December 31 (in thousands):
<TABLE>
<CAPTION>
UNITED STATES
AND
VENEZUELA RUSSIA CHINA OTHER TOTAL
--------- ------ ----- ------------ -----
<S> <C> <C> <C> <C> <C>
DECEMBER 31, 1997
Proved property costs $ 283,469 $ 48,176 $ 331,645
Costs excluded from amortization 7,742 842 $16,473 $ 6,531 31,588
Oilfield inventories 3,627 896 4,523
Less accumulated depletion (89,727) (8,276) (98,003)
--------- -------- ------- -------- ---------
$ 205,111 $ 41,638 $16,473 $ 6,531 $ 269,753
========= ======== ======= ======== =========
DECEMBER 31, 1996
Proved property costs $ 182,566 $ 45,523 $ 228,089
Costs excluded from amortization 8,935 809 $15,385 $ 858 25,987
Oilfield inventories 5,545 5,545
Less accumulated depletion (46,143) (5,197) (51,340)
--------- -------- ------- -------- ---------
$ 150,903 $ 41,135 $15,385 $ 858 $ 208,281
========= ======== ======= ======== =========
DECEMBER 31, 1995
Proved property costs $ 93,911 $ 37,070 $ 130,981
Costs excluded from amortization 14,001 3,215 $ 709 17,925
Properties held for sale (net of accumulated
depletion of $8,344,830) 22,885 22,885
Oilfield inventories 5,307 13 5,320
Less accumulated depletion (16,620) (2,450) (19,070)
--------- -------- -------- ---------
$ 96,599 $ 37,835 $ 23,607 $ 158,041
========= ======== ======== =========
</TABLE>
S-19
<PAGE> 53
The Company regularly evaluates its unproved properties to determine whether
impairment has occurred. The Company has excluded from amortization its interest
in unproved properties, the cost of uncompleted exploratory activities, and
portions of major development costs. The principal portion of such costs,
excluding those related to the acquisition of Crestone, is expected to be
included in amortizable costs during the next two to three years. The ultimate
timing of when the costs related to the acquisition of Crestone will be included
in amortizable costs is uncertain.
Excluded costs at December 31, 1997 consisted of the following by year incurred
(in thousands):
<TABLE>
<CAPTION>
TOTAL 1997 1996 1995 PRIOR TO 1995
----- ---- ---- ---- -------------
<S> <C> <C>
Property acquisition costs $15,106 $15,106
Exploration costs 16,482 13,195 2,042 $351 $894
------- ------- ------- ---- ----
$31,588 $13,195 $17,148 $351 $894
======= ======= ======= ==== ====
</TABLE>
Results of operations for oil and gas producing activities were (in thousands):
<TABLE>
<CAPTION>
VENEZUELA RUSSIA UNITED STATES TOTAL
--------- ------ ------------- -----
YEAR ENDED DECEMBER 31, 1997
<S> <C> <C> <C> <C>
Oil and gas revenues $154,119 $ 9,925 $ (87) $163,957
Expenses:
Lease operating costs and production taxes 34,516 7,349 22 41,887
Depletion 43,584 3,079 -- 46,663
-------- -------- -------- --------
Total expenses 78,100 10,428 22 88,550
-------- -------- -------- --------
Results of operations from oil and gas
producing activities $ 76,019 $ (503) $ (109) $ 75,407
======== ======== ======== ========
YEAR ENDED DECEMBER 31, 1996
Oil and gas revenues $136,840 $ 9,047 $ 4,676 $150,563
Expenses:
Lease operating costs and production taxes 17,669 6,605 243 24,517
Depletion 29,523 2,747 1,705 33,975
-------- -------- -------- --------
Total expenses 47,192 9,352 1,948 58,492
-------- -------- -------- --------
Results of operations from oil and gas
Producing activities $ 89,648 $ (305) $ 2,728 $ 92,071
======== ======== ======== ========
YEAR ENDED DECEMBER 31, 1995
Oil and gas revenues $ 49,174 $ 6,016 $ 7,683 $ 62,873
Expenses:
Lease operating costs and production taxes 6,483 2,764 1,456 10,703
Depletion 11,393 1,512 4,188 17,093
-------- -------- -------- --------
Total expenses 17,876 4,276 5,644 27,796
-------- -------- -------- --------
Results of operations from oil and gas
producing activities $ 31,298 $ 1,740 $ 2,039 $ 35,077
======== ======== ======== ========
</TABLE>
Beginning in 1995, GEOILBENT (owned 34% by the Company) has been included in the
consolidated financial statements based on a fiscal period ending September 30
and, accordingly, results of operations for oil and gas producing activities in
Russia for 1995 reflect the nine months ended September 30, 1995. Oil and gas
revenues and expenses in Russia for the quarter ended December 31, 1995 of $2.4
million and $2.0 million, respectively, have been included in the Company's
consolidated results of operations for 1996.
S-20
<PAGE> 54
In May 1994, the Company entered into a commodity hedge agreement designed to
reduce a portion of the Company's risk from oil price movements through December
31, 1996. Pursuant to the hedge agreement, the Company received $16.82 per Bbl
and paid the average price per Bbl of West Texas Intermediate Light Sweet Crude
Oil. Such terms applied to production of 1,000 Bbl of oil per day for 1994,
1,250 Bbl of oil per day in 1995 and 1,500 Bbl of oil per day for 1996. During
the years ended December 31, 1996 and 1995, respectively, the Company incurred
losses of $2,860,000 and $716,000, respectively, under the hedge agreement which
reduced oil and gas sales.
QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED)
Proved reserves are estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected to
be recovered through existing wells with existing equipment and operating
methods. All Venezuelan reserves are attributable to an operating service
agreement between Benton-Vinccler and P&G, under which all mineral rights are
owned by the government of Venezuela. Sales of reserves in place in 1995 include
reserves related to the United States properties sold in April 1996 (see Note
2), respectively.
The evaluations of the oil and gas reserves as of December 31, 1997, 1996, 1995
and 1994 were audited by Huddleston & Co., Inc., independent petroleum
engineers.
<TABLE>
<CAPTION>
UNITED MINORITY INTEREST
VENEZUELA RUSSIA STATES TOTAL IN VENEZUELA NET TOTAL
-----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
PROVED RESERVES - CRUDE OIL, CONDENSATE, AND
GAS LIQUIDS (MBBLS)
YEAR ENDED DECEMBER 31, 1997
Proved reserves beginning of the year 86,076 23,544 109,620 (17,215) 92,405
Revisions of previous estimates 17,043 3,449 20,492 (3,409) 17,083
Extensions, discoveries and improved 6,947 6,947 (1,389) 5,558
recovery
Production (15,395) (880) (16,275) 3,079 (13,196)
-------- -------- -------- ------- --------
Proved reserves end of year 94,671 26,113 120,784 (18,934) 101,850
======= ====== ======= ======== =======
YEAR ENDED DECEMBER 31, 1996
Proved reserves beginning of the year 73,593 22,618 96,211 (14,718) 81,493
Revisions of previous estimates (10,951) 712 (10,239) 2,190 (8,049)
Extensions, discoveries and improved 36,082 979 37,061 (7,216) 29,845
recovery
Production (12,648) (765) (13,413) 2,529 (10,884)
-------- -------- -------- -------- --------
Proved reserves end of year 86,076 23,544 109,620 (17,215) 92,405
======= ====== ======= ======= =======
YEAR ENDED DECEMBER 31, 1995
Proved reserves beginning of the year 60,707 17,540 233 78,480 (12,141) 66,339
Revisions of previous estimates (12,877) (107) (12,984) 2,575 (10,409)
Extensions, discoveries and improved 31,219 5,569 91 36,879 (6,243) 30,636
recovery
Production (5,456) (491) (69) (6,016) 1,091 (4,925)
Sales of reserves in place (148) (148) (148)
--------- ---------- ------ --------- ----------- --------
Proved reserves end of year 73,593 22,618 0 96,211 (14,718) 81,493
====== ====== ======= ======== ======== ========
PROVED DEVELOPED RESERVES AT:
December 31, 1997 68,868 5,443 74,311 (13,774) 60,537
December 31, 1996 47,805 3,417 0 51,222 (9,561) 41,661
December 31, 1995 30,032 3,475 0 33,507 (6,006) 27,501
January 1, 1995 12,580 2,772 155 15,507 (2,516) 12,991
PROVED RESERVES - NATURAL GAS (MMCF)
YEAR ENDED DECEMBER 31, 1996
Proved reserves beginning of the year 6 6 6
Production (1) (1) (1)
Sales of reserves in place (5) (5) (5)
--------- -------- ---------
Proved reserves end of year 0 0 0
========= ========= =========
YEAR ENDED DECEMBER 31, 1995
Proved reserves beginning of the year 16,077 16,077 16,077
Revisions of previous estimates (5,395) (5,395) (5,395)
Extensions, discoveries and improved 12,927 12,927 12,927
recovery
Production (3,785) (3,785) (3,785)
Sales of reserves in place (19,818) (19,818) (19,818)
------- ------- -------
Proved reserves end of year 6 6 6
=========== ========== ==========
PROVED DEVELOPED RESERVES AT:
December 31, 1995 6 6 6
January 1, 1995 8,385 8,385 8,385
</TABLE>
S-21
<PAGE> 55
(1) The Securities and Exchange Commission requires the reserve presentation
to be calculated using year-end prices and costs and assuming a
continuation of existing economic conditions. Proved reserves cannot be
measured exactly, and the estimation of reserves involves judgmental
determinations. Reserve estimates must be reviewed and adjusted
periodically to reflect additional information gained from reservoir
performance, new geological and geophysical data and economic changes. The
above estimates are based on current technology and economic conditions,
and the Company considers such estimates to be reasonable and consistent
with current knowledge of the characteristics and extent of production.
The estimates include only those amounts considered to be Proved Reserves
and do not include additional amounts which may result from new
discoveries in the future, or from application of secondary and tertiary
recovery processes where facilities are not in place.
(2) Proved Developed Reserves are reserves which can be expected to be
recovered through existing wells with existing equipment and operating
methods. This classification includes:
(a) Proved developed producing reserves which are reserves expected to be
recovered through existing completion intervals now open for
production in existing wells; and
(b) Proved developed nonproducing reserves which are reserves that exist
behind the casing of existing wells which are expected to be produced
in the predictable future, where the cost of making such oil and gas
available for production should be relatively small compared to the
cost of a new well.
Any reserves expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing primary
recovery methods are included as Proved Developed Reserves only after
testing by a pilot project or after the operation of an installed program
has confirmed through production response that increased recovery will be
achieved.
(3) Proved Undeveloped Reserves are Proved Reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where
a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage are limited to those drilling units offsetting
productive units, which are reasonably certain of production when drilled.
Proved Reserves for other undrilled units are claimed only where it can be
demonstrated with certainty that there is continuity of production from
the existing productive formation. No estimates for Proved Undeveloped
Reserves are attributable to or included in this table for any acreage for
which an application of fluid injection or other improved recovery
technique is contemplated unless proved effective by actual tests in the
area and in the same reservoir.
(4) The Company's engineering estimates indicate that a significant quantity
of natural gas reserves (net to the Company's interest) will be developed
and produced in association with the development and production of the
Company's proved oil reserves in Russia. The Company expects that, due to
current market conditions, it will initially reinject or flare such
associated natural gas production, and accordingly, no future net revenue
has been assigned to these reserves. Under the joint venture agreement,
such reserves are owned by the Company in the same proportion as all other
hydrocarbons in the field, and subsequent changes in conditions could
result in the assignment of value to these reserves.
(5) Changes in previous estimates of proved reserves result from new
information obtained from production history and changes in economic
factors.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVE QUANTITIES (UNAUDITED)
The standardized measure of discounted future net cash flows is presented in
accordance with the provisions of SFAS No. 69. In preparing this data,
assumptions and estimates have been used, and the Company cautions against
viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for
fixed and determinable escalations provided by contract, to the estimated future
production of year-end proved reserves. Future cash inflows were reduced by
estimated future production and development costs to determine pre-tax cash
inflows. Future income taxes were estimated by applying the year-end statutory
tax rates to the future pre-tax cash inflows, less the tax basis of the
properties involved, and adjusted for permanent differences and tax credits and
allowances. The resultant future net cash inflows are discounted using a ten
percent discount rate.
S-22
<PAGE> 56
The standardized measure of discounted future net cash flows as of December 31,
1997 was calculated using prices in effect at December 31, 1997, which averaged
$9.92 per Bbl. Had the standardized measure of discounted future net cash flows
been calculated using the average prices in effect on March 25, 1998, of $7.94
per Bbl, the standardized measure of discounted future net cash flows would have
been approximately $252.5 million.
GEOILBENT received a waiver from the export tariff assessed on all oil produced
in and exported from Russia for 1995. The discounted value of the waiver net to
the Company's interest as of December 31, 1994 was approximately $3 million. In
July 1996, such oil export tariffs were terminated in conjunction with a loan
agreement with the International Monetary Fund. Excise, pipeline and other taxes
continue to be levied on all oil producers and certain exporters. Although the
Russian regulatory environment has become less volatile, the Company is unable
to predict the impact of taxes, duties and other burdens for the future.
STANDARDIZED MEASURE
<TABLE>
<CAPTION>
MINORITY
UNITED INTEREST IN
VENEZUELA RUSSIA STATES TOTAL VENEZUELA NET TOTAL
--------------------------------------------------------------------------------------
(amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1997
Future cash inflow $ 923,421 $ 274,190 $ 1,197,611 $(184,684) $ 1,012,927
Future production costs (332,647) (74,326) (406,973) 66,529 (340,444)
Other related future costs (70,415) (53,283) (123,698) 14,083 (109,615)
----------- --------- ----------- --------- -----------
-- --
Future net revenue before income taxes 520,359 146,581 666,940 (104,072) 562,868
10% annual discount for estimated
timing of cash flows (156,321) (68,885) (225,206) 31,264 (193,942)
----------- --------- ----------- --------- -----------
Discounted future net cash flows
before income taxes 364,038 77,696 441,734 (72,808) 368,926
Future income taxes, discounted
at 10% per annum (72,567) (14,263) (86,830) 14,513 (72,317)
----------- --------- ----------- --------- -----------
Standardized measure of discounted
future net cash flows $ 291,471 $ 63,433 $ 354,904 $ (58,295) $ 296,609
=========== ========= =========== ========= ===========
DECEMBER 31, 1996
Future cash inflow $ 1,036,611 $ 291,951 $ 1,328,562 $(207,322) $ 1,121,240
Future production costs (347,498) (94,279) (441,777) 69,500 (372,277)
Other related future costs (65,454) (45,723) (111,177) 13,091 (98,086)
----------- --------- ----------- --------- -----------
Future net revenue before income taxes 623,659 151,949 775,608 (124,731) 650,877
10% annual discount for estimated
timing of cash flows (176,805) (61,244) (238,049) 35,361 (202,688)
----------- --------- ----------- --------- -----------
Discounted future net cash flows
before income taxes 446,854 90,705 537,559 (89,370) 448,189
Future income taxes, discounted at
10% per annum (123,304) (17,282) (140,586) 24,661 (115,925)
----------- --------- ----------- --------- -----------
Standardized measure of discounted
future net cash flows $ 323,550 $ 73,423 $ 396,973 $ (64,709) $ 332,264
=========== ========= =========== ========= ===========
DECEMBER 31,1995
Future cash inflow $ 652,110 $ 283,630 $ 19 $ 935,759 $(130,422) $ 805,337
Future production costs (170,328) (102,783) (2) (273,113) 34,066 (239,047)
Other related future costs (76,368) (36,686) 0 (113,054) 15,274 (97,780)
----------- --------- ------------ ----------- --------- -----------
Future net revenue before income taxes 405,414 144,161 17 549,592 (81,082) 468,510
10% annual discount for estimated
timing of cash flows (118,498) (58,800) (1) (177,299) 23,700 (153,599)
----------- --------- ------------ ----------- --------- -----------
Discounted future net cash flows
before income taxes 286,916 85,361 16 372,293 (57,382) 314,911
Future income taxes, discounted at
10% per annum (80,371) (29,927) 0 (110,298) 16,074 (94,224)
----------- --------- ------------ ----------- --------- -----------
Standardized measure of discounted
future net cash flows $ 206,545 $ 55,434 $ 16 $ 261,995 $ (41,308) $ 220,687
=========== ========= ============ =========== ========= ===========
</TABLE>
S-23
<PAGE> 57
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
CHANGES IN STANDARDIZED MEASURE 1997 1996 1995
--------- --------- ---------
(amounts in thousands)
<S> <C> <C> <C> <C>
Balance, January 1 $ 396,973 $ 261,995 $ 223,387
Changes resulting from:
Sales of oil and gas, net of related costs (122,179) (121,954) (52,170)
Revisions to estimates of proved reserves:
Pricing (102,357) 108,705 (6,990)
Quantities 82,211 (56,315) (63,802)
Sales of reserves in place (18) (28,102)
Extensions, discoveries and improved recovery,
net of future costs 25,725 183,968 170,037
Accretion of discount 53,756 37,230 33,632
Change in income taxes 53,756 (30,288) 2,635
Development costs incurred 61,207 63,013 47,657
Changes in timing and other (94,188) (49,363) (64,289)
--------- --------- ---------
Balance, December 31 $ 354,904 $ 396,973 $ 261,995
========= ========= =========
</TABLE>
NOTE 19 - 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)
YEAR ENDED DECEMBER 31, 1997
<S> <C> <C> <C> <C>
Revenues $46,299 $40,977 $45,188 $46,555
Expenses 28,966 30,418 36,603 41,173
------- ------- ------- -------
Income before incomes taxes and minority interest 17,333 10,559 8,585 5,382
Income taxes 5,984 4,432 4,492 2,569
------- ------- ------- -------
11,349 6,127 4,093 2,813
Minority interest 2,721 1,639 1,224 749
------- ------- ------- -------
Net income $ 8,628 $ 4,488 $ 2,869 $ 2,064
======= ======= ======= =======
Net income per common share:
Basic $ 0.30 $ 0.15 $ 0.10 $ 0.07
Diluted $ 0.28 $ 0.15 $ 0.09 $ 0.07
</TABLE>
S-24
<PAGE> 58
<TABLE>
<CAPTION>
QUARTER ENDED
---------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- -------- ------------ -----------
(amounts in thousands, except per share data)
YEAR ENDED DECEMBER 31, 1996
<S> <C> <C> <C> <C>
Revenues $ 32,939 $41,890 $40,901 $49,336
Expenses 19,853 20,935 22,809 32,620
-------- ------- ------- -------
Income before incomes taxes and minority interest 13,086 20,955 18,092 16,716
Income taxes 4,449 4,992 6,401 4,666
-------- ------- ------- -------
8,637 15,963 11,691 12,050
Minority interest 2,327 2,073 2,878 2,706
-------- ------- ------- -------
Income before extraordinary charge 6,310 13,890 8,813 9,344
Extraordinary charge for early
retirement of debt, net of tax benefit 10,075
-------- ------- ------- -------
Net income $ 6,310 $ 3,815 $ 8,813 $ 9,344
======== ======= ======= =======
Income per common share:
Basic:
Income before extraordinary
charge $ 0.24 $ 0.52 $ 0.32 $ 0.33
Extraordinary charge (0.38)
-------- ------- ------- -------
Net income $ 0.24 $ 0.14 $ 0.32 $ 0.33
======== ======= ======= =======
Diluted:
Income before extraordinary charge $ 0.22 $ 0.47 $ 0.29 $ 0.30
Extraordinary charge (0.34)
-------- ------- ------- -------
Net income $ 0.22 $ 0.13 $ 0.29 $ 0.30
======== ======= ======= =======
</TABLE>
S-25
<PAGE> 59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of
Carpinteria, State of California, on the 25th day of March, 1998.
BENTON OIL AND GAS COMPANY
------------------------------------
(Registrant)
Date: March 25, 1998 By: /s/ A.E. Benton
------------------------ ---------------------------------
A.E. Benton
Chief Executive Officer and
Principal Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed by the following persons on the 25th day of March,
1998, on behalf of the Registrant in the capacities indicated:
Signature Title
/s/A. E. Benton Chairman, Chief Executive Officer,
--------------------------------- President and Director
A. E. Benton
(Principal Executive Officer)
/s/James M. Whipkey Senior Vice President, Chief Financial
-------------------------------- Officer and Treasurer
James M. Whipkey
(Principal Financial Officer)
/s/Chris C. Hickok Vice President - Controller
------------------------------
Chris C. Hickok
(Principal Accounting Officer)
/s/Michael B. Wray Director
------------------------------
Michael B. Wray
/s/Bruce M. McIntyre Director
------------------------------
Bruce M. McIntyre
/s/Richard W. Fetzner Director
------------------------------
Richard W. Fetzner
/s/Garrett A. Garrettson Director
------------------------------
Garrett A. Garrettson
<PAGE> 1
EXHIBIT 21.1
BENTON OIL AND GAS COMPANY
LIST OF SUBSIDIARIES
--------------------
JURISDICTION
NAME OF INCORPORATION
-------------------------------- ----------------------
Benton-Vinccler, C.A.* Venezuela
Energy International Financial Institution, Ltd.* Cayman Islands
Crestone Energy Corporation Colorado
CEC Holding Company Delaware
The names of certain subsidiaries have been omitted in reliance upon Item 601
(b) (21) (ii) of Regulation S-K.
*All subsidiaries are wholly-owned by Benton Oil and Gas Company, except
Benton-Vinccler, C.A. and Energy International Financial Institution which are
owned 80% by Benton Oil and Gas Company.
<PAGE> 1
EXHIBIT 23.1
BENTON OIL AND GAS COMPANY
INDEPENDENT AUDITORS' CONSENT
-----------------------------
We consent to the incorporation by reference in Registration Statement Nos.
33-37124 on Form S-8, 33-70146 on Form S-3, 33-77946 on Form S-3, 333-135 on
Form S-3, 333-17231 on Form S-3 and 333-19679 on Form S-8 of Benton Oil and Gas
Company of our report dated March 24, 1998 appearing in this Annual Report on
Form 10-K of Benton Oil and Gas Company for the year ended December 31, 1997.
Deloitte & Touche LLP
Los Angeles, California
March 27, 1998
<PAGE> 1
EXHIBIT 23.2
BENTON OIL AND GAS COMPANY
INDEPENDENT PETROLEUM ENGINEERS' CONSENT
Huddleston & Co., Inc., hereby consents to the use of its name in reference
to it regarding its audit of the Benton Oil and Gas Company reserve reports,
dated as of December 31, 1997, in the Form 10-K Annual Report of Benton Oil
and Gas Company to be filed with the Securities and Exchange Commission.
Peter D. Huddleston, P.E.
Huddleston & Co., Inc.
Houston, Texas
March 25, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K
FOR THE PERIOD ENDED DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<EXCHANGE-RATE> 1
<CASH> 11,940
<SECURITIES> 156,436
<RECEIVABLES> 53,408
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 224,295
<PP&E> 373,490
<DEPRECIATION> 100,293
<TOTAL-ASSETS> 584,277
<CURRENT-LIABILITIES> 58,350
<BONDS> 280,016
0
0
<COMMON> 295
<OTHER-SE> 197,437
<TOTAL-LIABILITY-AND-EQUITY> 584,277
<SALES> 163,957
<TOTAL-REVENUES> 179,019
<CGS> 89,479
<TOTAL-COSTS> 89,479
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 24,245
<INCOME-PRETAX> 41,859
<INCOME-TAX> 17,477
<INCOME-CONTINUING> 18,049
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 18,049
<EPS-PRIMARY> 0.62
<EPS-DILUTED> 0.59
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
FOR THE PERIOD ENDED MARCH 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> MAR-31-1997
<EXCHANGE-RATE> 1
<CASH> 41,450
<SECURITIES> 45,058
<RECEIVABLES> 61,645
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 153,733
<PP&E> 279,819
<DEPRECIATION> 62,548
<TOTAL-ASSETS> 445,460
<CURRENT-LIABILITIES> 47,654
<BONDS> 176,554
0
0
<COMMON> 290
<OTHER-SE> 184,281
<TOTAL-LIABILITY-AND-EQUITY> 445,460
<SALES> 43,476
<TOTAL-REVENUES> 46,299
<CGS> 17,992
<TOTAL-COSTS> 17,992
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 5,485
<INCOME-PRETAX> 17,333
<INCOME-TAX> 5,984
<INCOME-CONTINUING> 8,628
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 8,628
<EPS-PRIMARY> 0.30
<EPS-DILUTED> 0.28
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
FOR THE PERIOD ENDED JUNE 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> JUN-30-1997
<EXCHANGE-RATE> 1
<CASH> 36,548
<SECURITIES> 55,427
<RECEIVABLES> 44,741
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 145,984
<PP&E> 311,548
<DEPRECIATION> 72,877
<TOTAL-ASSETS> 459,191
<CURRENT-LIABILITIES> 51,441
<BONDS> 176,507
0
0
<COMMON> 291
<OTHER-SE> 188,539
<TOTAL-LIABILITY-AND-EQUITY> 459,191
<SALES> 80,476
<TOTAL-REVENUES> 87,276
<CGS> 37,220
<TOTAL-COSTS> 37,220
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 11,271
<INCOME-PRETAX> 27,892
<INCOME-TAX> 10,416
<INCOME-CONTINUING> 13,116
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 13,116
<EPS-PRIMARY> 0.45
<EPS-DILUTED> 0.43
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
FOR THE PERIOD ENDED SEPTEMBER 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<EXCHANGE-RATE> 1
<CASH> 32,955
<SECURITIES> 51,159
<RECEIVABLES> 52,406
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 142,875
<PP&E> 344,064
<DEPRECIATION> 85,487
<TOTAL-ASSETS> 478,096
<CURRENT-LIABILITIES> 64,891
<BONDS> 176,489
0
0
<COMMON> 292
<OTHER-SE> 192,504
<TOTAL-LIABILITY-AND-EQUITY> 478,096
<SALES> 121,869
<TOTAL-REVENUES> 132,464
<CGS> 62,540
<TOTAL-COSTS> 62,540
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 16,726
<INCOME-PRETAX> 36,477
<INCOME-TAX> 14,908
<INCOME-CONTINUING> 15,985
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 15,985
<EPS-PRIMARY> 0.55
<EPS-DILUTED> 0.52
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
FORMTHE PERIOD ENDED MARCH 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> MAR-31-1996
<EXCHANGE-RATE> 1
<CASH> 7,804
<SECURITIES> 0
<RECEIVABLES> 34,427
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 64,198
<PP&E> 195,646
<DEPRECIATION> 27,715
<TOTAL-ASSETS> 234,893
<CURRENT-LIABILITIES> 61,472
<BONDS> 46,050
0
0
<COMMON> 261
<OTHER-SE> 117,735
<TOTAL-LIABILITY-AND-EQUITY> 234,893
<SALES> 31,285
<TOTAL-REVENUES> 32,939
<CGS> 11,805
<TOTAL-COSTS> 11,805
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 2,260
<INCOME-PRETAX> 13,086
<INCOME-TAX> 4,449
<INCOME-CONTINUING> 6,310
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 6,310
<EPS-PRIMARY> 0.24
<EPS-DILUTED> 0.22
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
FOR THE PERIOD ENDED JUNE 30, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> JUN-30-1996
<EXCHANGE-RATE> 1
<CASH> 13,785
<SECURITIES> 79,909
<RECEIVABLES> 35,447
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 168,142
<PP&E> 190,029
<DEPRECIATION> 33,187
<TOTAL-ASSETS> 330,832
<CURRENT-LIABILITIES> 57,711
<BONDS> 127,174
0
0
<COMMON> 273
<OTHER-SE> 134,227
<TOTAL-LIABILITY-AND-EQUITY> 330,832
<SALES> 64,371
<TOTAL-REVENUES> 74,828
<CGS> 24,056
<TOTAL-COSTS> 24,056
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 5,641
<INCOME-PRETAX> 34,041
<INCOME-TAX> 9,442
<INCOME-CONTINUING> 20,200
<DISCONTINUED> 0
<EXTRAORDINARY> (10,075)
<CHANGES> 0
<NET-INCOME> 10,125
<EPS-PRIMARY> 0.38
<EPS-DILUTED> 0.35
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
FOR THE PERIOD ENDED SEPTEMBER 30, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> SEP-30-1996
<EXCHANGE-RATE> 1
<CASH> 22,647
<SECURITIES> 74,130
<RECEIVABLES> 44,016
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 142,192
<PP&E> 213,050
<DEPRECIATION> 41,131
<TOTAL-ASSETS> 387,971
<CURRENT-LIABILITIES> 52,023
<BONDS> 175,031
0
0
<COMMON> 277
<OTHER-SE> 146,315
<TOTAL-LIABILITY-AND-EQUITY> 387,971
<SALES> 102,417
<TOTAL-REVENUES> 115,729
<CGS> 38,083
<TOTAL-COSTS> 39,083
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,776
<INCOME-PRETAX> 52,133
<INCOME-TAX> 15,843
<INCOME-CONTINUING> 29,013
<DISCONTINUED> 0
<EXTRAORDINARY> (10,075)
<CHANGES> 0
<NET-INCOME> 18,938
<EPS-PRIMARY> 0.71
<EPS-DILUTED> 0.64
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K
FOR THE PERIOD ENDED DECEMBER 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<EXCHANGE-RATE> 1
<CASH> 32,432
<SECURITIES> 52,004
<RECEIVABLES> 59,997
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 150,524
<PP&E> 263,905
<DEPRECIATION> 52,870
<TOTAL-ASSETS> 435,745
<CURRENT-LIABILITIES> 52,107
<BONDS> 175,028
0
0
<COMMON> 289
<OTHER-SE> 174,610
<TOTAL-LIABILITY-AND-EQUITY> 435,745
<SALES> 147,703
<TOTAL-REVENUES> 165,066
<CGS> 59,043
<TOTAL-COSTS> 59,043
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 16,128
<INCOME-PRETAX> 68,849
<INCOME-TAX> 20,508
<INCOME-CONTINUING> 38,357
<DISCONTINUED> 0
<EXTRAORDINARY> (10,075)
<CHANGES> 0
<NET-INCOME> 28,282
<EPS-PRIMARY> 1.04
<EPS-DILUTED> 0.95
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K
FOR THE PERIOD ENDED DECEMBER 31, 1995 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<EXCHANGE-RATE> 1
<CASH> 6,180
<SECURITIES> 0
<RECEIVABLES> 24,939
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 51,648
<PP&E> 179,650
<DEPRECIATION> 19,982
<TOTAL-ASSETS> 214,750
<CURRENT-LIABILITIES> 54,535
<BONDS> 49,486
0
0
<COMMON> 255
<OTHER-SE> 103,426
<TOTAL-LIABILITY-AND-EQUITY> 214,750
<SALES> 62,157
<TOTAL-REVENUES> 65,068
<CGS> 28,114
<TOTAL-COSTS> 28,114
<OTHER-EXPENSES> 1,673
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7,497
<INCOME-PRETAX> 18,373
<INCOME-TAX> 2,478
<INCOME-CONTINUING> 10,591
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 10,591
<EPS-PRIMARY> 0.42
<EPS-DILUTED> 0.41
</TABLE>
