<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
Annual Report Under Section 13 or 15(d)
of the Securities Exchange Act of 1934
[X] For the fiscal year ended December 31, 1999 or
Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from ____________ to ________
Commission File No.: 1-10762
---------------------
BENTON OIL AND GAS COMPANY
(Exact name of registrant as specified in its charter)
Delaware 77-0196707
(State or other jurisdiction of (IRS Employer Identification Number)
incorporation or organization)
6267 Carpinteria Avenue, Suite 200
Carpinteria, California 93013
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (805) 566-5600
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Name of each exchange
Title of each class on which registered
- ------------------- -------------------
Common Stock, $.01 Par Value NYSE
Common Stock Purchase Warrants, $11.00 exercise price NASDAQ
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
On March 24, 2000, the aggregate market value of the shares of voting stock of
Registrant held by non-affiliates was approximately $86,412,117 based on a
closing sales price on NYSE of $3.00.
As of March 24 2000, 29,576,966 shares of the Registrant's common stock were
outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 2000 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
2
BENTON OIL AND GAS COMPANY
FORM 10-K
TABLE OF CONTENTS
Page
----
Part I
Item 1. Business.................................................3
Item 2. Properties..............................................19
Item 3. Legal Proceedings.......................................19
Item 4. Submission of Matters to a Vote of Security Holders ....20
Part II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters................21
Item 6. Selected Consolidated Financial Data....................22
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............23
Item 7A. Quantitative and Qualitative Disclosures about
Market Risk....................................33
Item 8. Financial Statements and Supplemental Data..............34
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ........34
Part III
Item 10. Directors and Executive Officers of the Registrant .....35
Item 11. Executive Compensation..................................35
Item 12. Security Ownership of Certain Beneficial
Owners and Management..........................35
Item 13. Certain Relationships and Related Transactions .........35
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................36
Financial Statements.......................................................38
Signatures.................................................................70
<PAGE> 3
3
PART I
The Company cautions that any forward-looking statements (as such term is
defined in the Private Securities Litigation Reform Act of 1995) contained in
this report or made by management of the Company involve risks and uncertainties
and are subject to change based on various important factors. When used in this
report, the words budget, budgeted, anticipate, expect, believes, goals or
projects and similar expressions are intended to identify forward-looking
statements. In accordance with the provisions of the Private Securities
Litigation Reform Act of 1995, the Company cautions that important factors could
cause actual results to differ materially from those in the forward-looking
statements. Such factors include the Company's substantial concentration of
operations in Venezuela, the political and economic risks associated with
international operations, the anticipated future development costs for the
Company's undeveloped proved reserves, the risk that actual results may vary
considerably from reserve estimates, the dependence upon the abilities and
continued participation of certain key employees of the Company, the risks
normally incident to the operation and development of oil and gas properties and
the drilling of oil and gas wells, the price for oil and natural gas, and other
risks indicated in filings with the Securities and Exchange Commission. The
following factors, among others, in some cases have affected and could cause
actual results and plans for future periods to differ materially from those
expressed or implied in any such forward-looking statements: fluctuations in oil
and gas prices, changes in operating costs, overall economic conditions,
political stability, acts of terrorism, currency and exchange risks, changes in
existing or potential tariffs, duties or quotas, availability of additional
exploration and development opportunities, availability of sufficient financing,
changes in weather conditions, and ability to hire, retain and train management
and personnel. See Risk Factors included in Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations.
ITEM 1. BUSINESS
GENERAL
Benton Oil and Gas Company (the "Company") is an independent energy company
which has been engaged in the development and production of oil and gas
properties since 1989. The Company has developed significant interests in
Venezuela and Russia, and has acquired certain interests in other parts of the
world. 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
limited liability company, Geoilbent, which operates the North Gubkinskoye Field
in West Siberia, Russia. The Company has expanded into projects which involve
exploration components such as in Russia through its ownership interest in
Arctic Gas Company ("Arctic Gas," formerly Severneftegaz); and in China through
the acquisition of the WAB-21 Exploration Block.
As of December 31, 1999, the Company had total assets of $276.3 million, total
estimated proved reserves net of minority interest of 148.1 MMBOE, and a
standardized measure of discounted future net cash flow, before income taxes,
for total proved reserves of $744.9 million. For the year ended December 31,
1999, the Company had total revenues, other income and equity earnings of $102.0
million.
The Company was incorporated in Delaware in September 1988. Its principal
executive offices are located at 6267 Carpinteria Avenue, Suite 200,
Carpinteria, California 93013, and its telephone number is (805) 566-5600.
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) 1999 1998 1997 1999 1998 1997
--------- ------- -------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
RESERVE INFORMATION:
Proved Reserves (MBOE) 107,969 110,268 75,737 40,129 31,053 26,113
Discounted Future Net Cash
Flow Attributable to Proved
Reserves, Before Income
Taxes $ 521,346 $49,964 $291,230 $223,589 $49,546 $77,696
Standardized Measure of Future
Net Cash Flows $ 380,865 $49,964 $233,176 $175,913 $43,248 $63,433
DRILLING AND PRODUCTION ACTIVITY:
Gross Wells Drilled 2 16 27 28 31 7
Average Daily Production (BOE) 26,485 33,349 42,178 3,975 2,530 2,411
</TABLE>
<PAGE> 4
4
<TABLE>
<CAPTION>
Venezuela (1) Russia (2)
--------------------------------- --------------------------------
(dollars in 000's) 1999 1998 1997 1999 1998 1997
-------- ------- -------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
FINANCIAL DATA:
Oil and Gas Revenues $ 89,060 $ 82,215 $154,119 $ 11,006 $ 8,059 $ 9,925
Expenses:
Operating Expenses and
taxes other than on income 38,841 39,069 34,516 4,139 4,445 6,551
Depletion 14,829 31,843 43,584 3,325 2,474 3,079
Write down of oil and gas
properties 187,811 - - 10,100 -
Income tax expense (benefit) 3,812 (26,793) 25,656 436 - -
-------- --------- -------- ------- -------- -------
Total Expenses 57,482 231,930 103,756 7,900 17,019 9,630
-------- --------- -------- ------- -------- -------
Results of Operations from
Oil and Gas Producing
Activities $ 31,578 $(149,715) $ 50,363 $ 3,106 $ (8,960) $ 295
======== ========= ======== ======= ======== =======
</TABLE>
(1) Includes reserve information net of a 20% deduction for the minority
interest in Benton-Vinccler. Drilling and production activity and
financial data are reflected without deduction for minority interest.
All Venezuelan reserves are attributable to an operating service
agreement between Benton-Vinccler and PDVSA under which all mineral
rights are owned by the Government of Venezuela. See "--South Monagas
Unit, Venezuela."
(2) Geoilbent (34% owned by the Company) and Arctic Gas Company (24% and
10% ownership not subject to certain sale and transfer restrictions at
December 31, 1999 and 1998, respectively), which are accounted for
under the equity method, have been included at their respective
ownership interest in the consolidated financial statements based on a
fiscal period ending September 30 and, accordingly, the financial
information for Russia represents the years ended September 30, 1999,
1998 and 1997 for Geoilbent and the year ended September 30, 1999 for
Arctic Gas.
SOUTH MONAGAS UNIT, VENEZUELA
GENERAL
In July 1992, the Company and Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), a Venezuelan construction and engineering company,
signed a 20-year operating service agreement with PDVSA to reactivate and
further develop the Uracoa, Tucupita and Bombal Fields, which are a part of the
South Monagas Unit (the "Unit"). At that time, the Company was one of three
foreign companies ultimately awarded an operating service agreement to
reactivate existing fields by PDVSA, and was the first U.S. company since 1976
to be granted such an oil field development contract in Venezuela.
The oil and gas operations in the Unit are conducted by Benton-Vinccler, the
Company's 80%-owned subsidiary. The remaining 20% of the outstanding capital
stock of Benton-Vinccler is owned by Vinccler. The Company, through its majority
ownership of stock in Benton-Vinccler, makes all operational and corporate
decisions related to Benton-Vinccler, subject to certain super-majority
provisions of Benton-Vinccler's charter documents related to mergers,
consolidations, sales of substantially all of its corporate assets, change of
business and similar major corporate events. Vinccler has an extensive operating
history in Venezuela. It has provided Benton-Vinccler with initial financial
assistance and significant construction services, and continues to provide
ongoing assistance with governmental and labor relations.
Under the terms of the operating service agreement, Benton-Vinccler is a
contractor for PDVSA and is responsible for overall operations of the Unit,
including all necessary investments to reactivate and develop the fields
comprising the Unit. The Venezuelan government maintains full ownership of all
hydrocarbons in the fields. In addition, PDVSA maintains full ownership of
equipment and capital infrastructure following its installation. Benton-Vinccler
invoices PDVSA each quarter based on Bbls of oil accepted by PDVSA during the
quarter, using quarterly adjusted contract service fees per Bbl, and receives
its payments from PDVSA in U.S. dollars deposited directly into a U.S. bank
account. The operating service agreement provides for Benton-Vinccler to receive
an operating fee for each Bbl of crude oil delivered and a capital recovery fee
for certain of its capital expenditures, provided that such operating fee and
capital recovery fee cannot exceed the maximum total fee per Bbl set forth in
the agreement. The operating fee is subject to periodic adjustments to reflect
changes in the special energy index of the U.S. Consumer Price Index, and the
maximum total fee is subject to periodic adjustments to reflect changes in the
average of certain world crude oil prices. Since commencement of operations, the
Company has received approximately $11 million in capital recovery fees. 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> 5
5
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,
1999, proved reserves attributable to the Company's Venezuelan operations were
134,961 MBOE (107,969 MBOE net to the Company), which represented approximately
73% of the Company's proved reserves. Benton-Vinccler is primarily developing
the Oficina sands in the Uracoa Field, which contain 77% of the Unit's proved
reserves and has begun the development of the Tucupita and Bombal Fields which
contain the remaining 23% 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
Benton-Vinccler contracts with third parties for drilling and completion of
wells. In December 1999, the Company entered into agreements with Schlumberger
and Helmerich & Payne to further develop the Unit pursuant to a long-term
incentive-based alliance program. The alliance program, which includes the
drilling of up to 80 wells through 2001, provides for financial incentives for
Schlumberger and Helmerich & Payne that are intended to reduce drilling costs,
improve initial production rates of new wells and to increase the average life
of the downhole pumps at South Monagas. As part of Schlumberger's commitment to
the program, it will provide additional technical and engineering resources
on-site full-time in Venezuela and at the Company's offices in Carpinteria,
California.
Uracoa Field
Benton-Vinccler has been developing the Unit since 1992, beginning with the
Uracoa Field. During March 2000 (through March 24), a total of approximately 95
wells were producing an average of approximately 20,686 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 (BBLS)
---------- ------------ ----------------------------
<S> <C> <C> <C>
1997:
First Quarter 2 6 36,100
Second Quarter 4 4 35,800
Third Quarter 1 6 40,500
Fourth Quarter 1 2 44,400
1998:
First Quarter - - 37,700
Second Quarter - - 32,600
Third Quarter 2 - 26,500
Fourth Quarter 3 3 25,900
1999:
First Quarter - - 24,300
Second Quarter - - 22,800
Third Quarter - - 21,300
Fourth Quarter - - 21,000
</TABLE>
Daily production rates have declined since the fourth quarter of 1997 due to a
reduction in drilling activity, natural reservoir decline, and production
related problems. Drilling operations ended in the fourth quarter of 1997 as the
initial development plan for the Uracoa Field was completed. Without continuous
drilling, reservoirs like those at the Uracoa Field initially experience a sharp
natural decline that decreases with time. This initial sharp natural decline was
aggravated during 1998 due to the impact of production problems on certain wells
and the degradation of the local electrical power source. Solutions to the
electrical power and production related problems were identified in 1998, but
the installation of electrical power generation facilities and remediation work
on wells was required into 1999. Additionally, the Company focused its efforts
on the completion of a detailed geologic and reservoir simulation study during
1998, which identified up to 80 new infill and development well locations.
Drilling resumed in the second half of 1998, but was suspended again in 1999 due
to uncertainties in oil prices and cash flows. Capital expenditures were limited
during this period primarily to workovers and remediation activities.
<PAGE> 6
6
Since 1992, 15 previously drilled wells have been reactivated and 112 new wells
have been drilled in the Uracoa Field using modern drilling and completion
techniques that had not previously been utilized on the field. 100 wells, or
89%, have been completed and placed on production, 1 well was converted to
injection and 9 injection wells have been drilled.
The Company has completed a geologic and reservoir simulation study with
advanced analytical software and new core data. The geologic and reservoir
simulation study indicates the viability of at least 80 additional primary
infill wells in the Uracoa Field. Many of these new locations are in
underdeveloped sands where the model was used to optimize well spacing and
location. In the more developed sands, the model was used to verify the economic
viability of infill locations. The alliance program with Schlumberger and
Helmerich & Payne is intended to drill the majority of these wells. However, if
oil prices decline significantly, the timing of the drilling of the additional
wells will depend on the Company's ability to generate sufficient cash flow from
operations or to obtain additional funding from other sources to fund the
drilling program.
Oil, water and gas produced from the Uracoa Field are processed in the UM-2
production facility. Processed oil is shipped via pipeline to the PDVSA custody
transfer point. Produced water is treated and filtered, and then re-injected
into the aquifer to assist the natural water drive, while gas is re-injected
into the gas cap for reservoir pressure maintenance. The major components of
this state-of-the-art process facility were designed in the United States and
installed by Benton-Vinccler. This process design is commonly used in heavy oil
production in the United States, but was not previously used extensively in
Venezuela to process crude oil of similar gravity or quality. The current
production facility has capacity to handle 60 MBbls of oil per day, 130 MBbls of
water per day, and 50 Mmcf of gas per day.
Benton-Vinccler's 2000 capital expenditure budget includes the drilling of
approximately 50 wells at an estimated cost of $43 million. The drilling of
additional wells will depend on the Company's ability to generate sufficient
cash flow from operations or to obtain additional funding from other sources to
fund such additional drilling.
In August 1999, Benton-Vinccler sold its recently constructed power generation
facility located in the Uracoa Field for $15.1 million. Concurrently with the
sale, Benton-Vinccler entered into a long-term power purchase agreement with the
purchaser of the facility to provide for the electrical needs of the field
throughout the remaining term of the operating service agreement. The cost of
electricity to be provided under terms of the power purchase agreement
approximates that previously paid by Benton-Vinccler to local utilities.
Tucupita and Bombal Fields
Before becoming inactive in 1987, the Tucupita Field had been substantially
developed, having produced 67.1 MMBbls of oil, 34.7 MMBbls of water and 17.6 Bcf
of natural gas. Benton-Vinccler drilled a successful pilot horizontal well in
late 1996 to evaluate the remaining development potential of the Tucupita field.
This well has produced 1.5 MMBbls of oil at an average rate of 1,286 Bbls of oil
per day. The early success of this pilot horizontal well led to the drilling of
a second horizontal well in 1998. Initial oil rates from the horizontal wells
were encouraging, but water production soon increased sharply. As a result, the
redevelopment strategy was changed to include drilling deviated wells to allow
for more effective water shut-off. During the second half of 1998, five deviated
infill wells were drilled to target undepleted portions of the field. All five
wells encountered high oil saturations, with an average initial production rate
of 922 Bbls of oil per day. Additionally, nine old wells have been reactivated,
bringing current production levels to 4,500 Bbls of oil per day.
In 1999, Benton Vinccler drilled a well on the west portion of the Tucupita
Field to test the commercial viability of a previously undrilled fault block
identified using 3-D seismic data. The well proved to be non-commercial.
Produced water from Tucupita is reinjected into the aquifer to aid the natural
water drive, while produced gas is being flared. The oil is trucked back to the
Uracoa facilities where it is processed and shipped by pipeline to the custody
transfer point.
Eleven new well locations have been identified in undepleted portions of the
Tucupita Field, and additional viable wells are anticipated once a simulation
study is completed for Tucupita. Moreover, analysis of petrophysical and
production data has revealed significant behind-pipe recompletion potential in a
deeper pay section that was not a primary target during the earlier development
of the field. Currently, 14 wells with recompletion potential have been
identified for reactivation.
Given the results of the reservoir simulation study and success of the infill
program to date, Benton-Vinccler is analyzing alternatives for outsourcing an
oil pipeline from Tucupita to the UM-2 processing facility at Uracoa. The
prospective pipeline, if constructed, would also be used to transport oil from
the Bombal Field. Currently, crude oil is transported by trucks from both
Tucupita and Bombal, so a pipeline would significantly reduce transportation
costs from both fields and allow increased volumes of oil to be produced. To
date, Benton-Vinccler has drilled one well in the Bombal Field and reactivated
another, resulting in current production of 320 Bbls of oil per day. Future
plans include drilling up to 26 development wells and installing a processing
facility to separate the oil, water and natural gas. Initially, the water and
gas will be re-injected back into the reservoir.
<PAGE> 7
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CUSTOMERS AND MARKET INFORMATION
Oil produced in Venezuela is delivered to PDVSA under the terms of an operating
service agreement for an operating service fee. Benton-Vinccler has constructed
a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA's
storage facility, which is the custody transfer point. The service agreement
specifies that the oil stream may contain no more than 1% base sediment and
water, and quality measurements are conducted both at Benton-Vinccler's
facilities and at PDVSA's storage facility. A continuous flow measuring unit is
installed at Benton-Vinccler's facility, so that quantity is monitored
constantly. PDVSA provides Benton-Vinccler with a daily acknowledgment regarding
the amount of oil accepted the previous day, which is reconciled to
Benton-Vinccler's measurement. At the end of each quarter, Benton-Vinccler
prepares an invoice to PDVSA for that quarter's deliveries. PDVSA pays the
invoice at the end of the second month after the end of the quarter. Invoice
amounts and payments are denominated in U.S. dollars. Payments are wire
transferred into Benton-Vinccler's account in a commercial bank in the United
States.
EMPLOYEES; COMMUNITY RELATIONS
Benton-Vinccler seeks to employ nationals rather than bring expatriates into the
country. Presently, there are 6 full-time expatriates working with
Benton-Vinccler and 155 local employees. Benton-Vinccler also has conducted
community relations programs, providing medical care, training, equipment and
supplies, and support for local schools, in both states in which the Unit falls.
DELTA CENTRO BLOCK, VENEZUELA
GENERAL
In January 1996, the Company and its bidding partners, Louisiana Land and
Exploration, which has been subsequently acquired by Burlington Resources Inc.
("Burlington"), and Norcen Energy Company, which has been subsequently acquired
by Union Pacific Resources Group Inc. ("UPR"), were awarded the right to explore
and develop the Delta Centro Block in eastern Venezuela. The contract requires a
minimum exploration work program consisting of completing a 550 square kilometer
3-D and a 289 kilometer 2-D seismic survey and drilling three wells to depths of
12,000 to 18,000 feet within five years. PDVSA estimated that this minimum
exploration work program would cost $60.0 million, and required that the
partners each post a performance surety bond or standby letter of credit for its
pro rata share of the estimated work commitment expenditures. The Company
provided a standby letter of credit in the amount of $18.0 million. The Company
has a 30% interest in the exploration venture, with the other partners each
owning a 35% interest. Under the terms of the operating agreement, which
establishes the management company for the project, Burlington is the operator
of the block, and therefore the Company does not exercise control of the
operations of the venture. If commercial operations result from the exploration
activities, it is anticipated that Corporacion Venezolana del Petroleo, S.A.
("CVP"), an affiliate of PDVSA, will have a 35% interest in the management
company, which will dilute the voting power of the partners on a pro rata basis.
If areas within the block are deemed to be commercially viable, then the group
has the right to enter into further agreements with CVP to develop those areas
during the next 20-25 years. CVP would participate in the revenues and costs
with an interest between 1 and 35%, at CVP's discretion. Any oil and gas
produced by the Delta Centro consortium will be sold at market prices and will
be subject to the oil and gas taxation regime in Venezuela and to the terms of a
profit sharing agreement with PDVSA. Under the current oil and gas tax law, a
royalty of up to 16.66% will be paid to the state. Under the contract bid terms,
41% of the pre-tax income will be shared with PDVSA for the period during which
the first $1.0 billion of revenues is produced; thereafter, the profit sharing
amount may increase to up to 50% according to a formula based on return on
assets. Currently, the statutory income tax rate for oil and gas enterprises is
67.7%. Royalties and shared profits are currently deductible for tax purposes.
LOCATION AND GEOLOGY
The Delta Centro Block consists of approximately 2,100 square kilometers
(526,000 acres) located in the delta of the Orinoco River 12 miles north of the
South Monagas Unit. Although no significant exploratory activity had previously
been conducted on the block prior to being made available for bids in 1995,
PDVSA estimated that the area might contain recoverable oil reserves of as much
as 820 MMBbls, and might 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. 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 and its partners have
significant experience in seismic and drilling operations.
<PAGE> 8
8
DRILLING AND DEVELOPMENT ACTIVITY
The venture has acquired a 595 square kilometer 3-D seismic survey over the
southwestern portion of the Delta Centro Block and a 371 kilometer 2-D seismic
survey to evaluate the remaining exploration potential of the block. During
1999, the Block's first exploration well, the Jarina 1-X, penetrated a thick
potential reservoir sequence, but encountered no commercial hydrocarbons. The
Company continues to evaluate the remaining leads on the Block, including their
potential reserves and risk factors, although the block's future commerciality
is uncertain. As of December 31, 1999, the Company's share of expenditures to
date was $15.2 million, all of which had been included in the Venezuela cost
center, and the standby letter of credit had been reduced to $7.7 million.
COMMUNITY AND COUNTRY RELATIONS
The Company has conducted a community relations program in the area, providing
medical care, equipment and supplies to the Warao tribe which resides in this
area.
NORTH GUBKINSKOYE, RUSSIA
GENERAL
In December 1991, the joint venture agreement forming Geoilbent among the
Company (34% interest) and two Russian partners, Purneftegazgeologia and
Purneftegaz (each having a 33% interest), was registered with the Ministry of
Finance of the USSR. In November 1993, the agreement was registered with the
Russian Agency for International Cooperation and Development. 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.
Geoilbent may only take action through a 67% majority vote of the partners.
LOCATION AND GEOLOGY
Geoilbent develops, produces and markets crude oil from the North Gubkinskoye
Field in the West Siberia region of Russia, located approximately 2,000 miles
northeast of Moscow. The field, which covers an area approximately 15 miles long
and 4 miles wide, has been delineated with over 60 exploratory wells (which
tested 26 separate reservoirs) and is surrounded by large proven fields. The
field is a large anticlinal structure with multiple pay sands. The development
to date has focused on the BP 8, 9, 10, 11 and 12 reservoirs with minor
development in the BP 6 and 7 reservoirs. The produced natural gas is currently
being flared in accordance with environmental regulations.
<PAGE> 9
9
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 2000 (through March 24),
approximately 77 wells were producing an average of approximately 11,800 Bbls 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 (BBLS)
------------- ----------------------------
<S> <C> <C>
1997:
First Quarter 1 6,300
Second Quarter 2 6,800
Third Quarter 1 6,800
Fourth Quarter 3 6,600
1998:
First Quarter 10 7,600
Second Quarter 9 8,600
Third Quarter 7 9,900
Fourth Quarter 5 9,900
1999:
First Quarter 5 10,500
Second Quarter 6 11,400
Third Quarter 8 13,000
Fourth Quarter 9 13,200
</TABLE>
Geoilbent contracts with third parties for drilling and completion of wells. To
date, 19 previously drilled wells have been reactivated and 110 wells have been
drilled in the field, with 97 wells, or 88%, completed and placed on production.
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"). A total of $48.5 million has been advanced from the EBRD Credit
Facility as of December 31, 1999. Additional borrowing will be based on
achieving certain reserve and production milestones. Geoilbent has a 2000
capital expenditure budget of approximately $34 million, of which $15 million
would be used to drill 43 wells in the North Gubkinskoye Field and $19 million
would be used for construction of production and other facilities. This budget
will be dependent upon increased availability to draw from the EBRD Credit
Facility and cash flow from operations.
CUSTOMERS AND MARKET INFORMATION
Geoilbent's 37-mile pipeline runs from the field to the main pipeline in the
area where Geoilbent transfers the oil to Transneft, the state oil pipeline
monopoly. Transneft then transports the oil to the western border of Russia for
export sales or to various domestic locations for non-export sales. All export
oil sales are handled by trading companies such as Russoil or NAFTEX Moscow. All
export sales have been paid in U.S. dollars into Geoilbent's account in Moscow.
<PAGE> 10
10
EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS
Having access to the oilfield labor base in West Siberia, Geoilbent employs
Russian nationals almost exclusively. Presently, there are two full-time
expatriates working with Geoilbent and 501 local employees. The Company has
conducted community relations programs in Russia, providing medical care,
training, equipment and supplies in towns in which Geoilbent personnel reside
and also for the nomadic indigenous population which resides in the area of
oilfield operations.
EAST URENGOY, RUSSIA
GENERAL
Arctic Gas Company, formerly Severneftegaz, was formed in 1992 as a private
company to explore and develop the Samburg and Yevo-Yakha License Blocks, which
are located in the prolific Urengoy gas province of West Siberia. Under the
terms of the Cooperation Agreement signed in April 1998 ("Cooperation
Agreement"), the Company acquired an initial 40% interest in Arctic Gas in
return for providing or arranging up to $100 million of credit financing for the
project.
The Cooperation Agreement imposes restrictions on the sale and transfer of these
shares subject to disbursements under the credit facility, and provides that for
every $2.5 million of credit made available, 1% of the shares will be released
from the restrictions on sale and transfer. As of December 31, 1999, the Company
had provided $13.4 million of credit, of which approximately $12.6 million had
been applied to the release of restrictions on the shares. As a result, the
Company had earned the right to remove restrictions from shares representing an
approximate 5% equity interest.
The Company owned a total of 59% voting shares of Arctic Gas as of December 31,
1999, of which 24% was not subject to restrictions. At December 31, 1998, the
Company owned a total of 50% voting shares of Arctic Gas, of which 10% was not
subject to restrictions.
LOCATION AND GEOLOGY
The Samburg and Yevo-Yakha License Blocks comprise approximately 823,000 acres
and are situated nearly 1,740 miles northeast of Moscow in the Yamal-Nenets
Autonomous Region of Russia. The towns and communities of Novy Urengoy, Samburg,
Urengoy and Nyda are located near the two licenses. Extensive exploration
drilling and testing on the Samburg and Yevo-Yakha licenses has resulted in the
discovery of major reserves of gas, condensate and oil. The primary reservoirs
of these fields are currently being produced in both the adjacent Urengoy Field
and Rospan Block. These reserves represent strategic resources for Russian
domestic energy in addition to being a high quality export product. Historic
production at the Urengoy Field is now on decline, and the undeveloped reserves
discovered on the adjacent Arctic Gas and Rospan Blocks are of interest to
Gazprom and Russia as replacement for the production that is being lost at
Urengoy.
The Samburg and Yevo-Yakha License Blocks are located within the West Siberian
Basin, the world's largest sedimentary basin, which contains nearly one third of
the world's proved and probable gas reserves. Both license blocks occur on the
eastern flank of the giant Urengoy gas field, which currently produces
hydrocarbons from cenomanian reservoirs.
DRILLING AND DEVELOPMENT ACTIVITY
Arctic Gas has recently reactivated one previously drilled oil well and is
working on a second in the Samburg Field. Oil is being trucked to storage
facilities where it is collected for sales. Approximately 550 Bbls of oil per
day are being produced in this fashion. Proceeds from oil sales are intended to
help cover a portion of the operating and administrative costs of Arctic Gas.
The planning for a Samburg natural gas pilot development project is underway.
The pilot project calls for the the drilling of new wells, installation of gas
processing facilities and connection into the export pipeline system. Due to
their proximity to the Urengoy Field and its existing infrastructure, both of
Arctic Gas's blocks are well situated for fast track development. Preliminary
agreements are already in place between Arctic Gas and Gazprom to allow access
to existing gas and condensate pipelines and facilities that could result in
product sales to European markets. The Arctic Gas blocks are located in the
heart of Urengoy/Yamburg producing and support infrastructure region. Natural
gas export trunklines are located 11 kilometers from the blocks. Discussions are
underway with Gazprom concerning the transportation of Arctic Gas's gas, as well
as with various parties concerning the export and marketing of the gas. Gazprom
has granted Arctic Gas access to its transportation system beginning in the
third quarter of 2001 for gas sales from the blocks to certain customers in the
former Soviet Union The blocks are also close to railroads for possible liquids
transportation.
Further development activities are subject to the Company's ability to provide
or arrange further funding.
<PAGE> 11
11
EMPLOYEES
Presently, there is one full-time expatriate working with Arctic Gas and 73
local employees.
WAB-21, SOUTH CHINA SEA
GENERAL
In December 1996, the Company acquired Benton Offshore China Company, formerly
Crestone Energy Corporation, a privately held company headquartered in Denver,
Colorado. Benton Offshore China Company's principal asset is a petroleum
contract with China National Offshore Oil Company ("CNOOC") for the WAB-21 area.
The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea,
with an option for an additional 1.0 million acres under certain circumstances.
LOCATION AND GEOLOGY
The WAB-21 Contract Area (the "Contract Area") is located approximately 50 miles
southeast of the Dai Hung (Big Bear) Oil Field. The block is adjacent to British
Petroleum's recent giant gas discovery at Lan Tay (Red Orchid) and 100 miles
north of Exxon's Natuna Discovery. The Contract Area covers several similar
structural trends each with potential for large hydrocarbon reserves in possible
multiple pay zones.
The Contract Area is located northwest of Zengmu Basin (Offshore Sarawak), where
two Chinese institutions have already conducted geophysical seismic surveys.
Based on the multi-disciplinary data available from Zengmu Basin to the
southeast, East Natuna Basin to the south and southwest, and WAN'AN (Con Son)
Basin to the west and northwest there is substantial evidence of significant
hydrocarbon potential in the Contract Area.
POLITICAL CONSIDERATIONS AND RISKS
China's claim of ownership of the area results from China's discovery and
China's use and historic administration of the area. This claim also includes
third party and official foreign government recognition of China's sovereignty
and jurisdiction over the Contract Area.
The nearby Nansha Islands were formally placed under Chinese administration
during the Ming Dynasty (1368-1644 AD). In 1883, Germans were banned from
geologically surveying the area by the Qing court, based on Chinese sovereignty
over the region. Since the establishment of Chinese government jurisdiction over
the area several hundred years ago, the Nansha Islands have long been recognized
as being Chinese territory. Additionally, Russian and Vietnamese maps have
historically shown this area as Chinese. Significantly, even Vietnam recognized
China's sovereignty of the islands from 1956 until 1975. Vietnam's former
Premier Van Dong acknowledged China's Nansha Islands sovereignty in a diplomatic
note in 1958.
In April 1994, a Chinese seismic survey ship was intercepted by Vietnamese boats
in the Contract Area while attempting to conduct seismic acquisition operations.
The Chinese ship returned to its port without commencing its seismic work
program. China subsequently denounced Vietnam's action.
Since 1994 China has maintained publicly that it is willing to discuss the joint
development of the Contract Area with the Vietnamese government. However,
Vietnam has granted exploration and development rights to parts of the Contract
Area to Conoco Inc. Recently, high level discussions between officials of CNOOC
and PetroVietnam have resulted in preliminary agreements on resolving
territorial disputes in nearby areas, although there is no certainty of timing
or the outcome of such discussions. Significant progress has been made in the
disputed Hainan Island/Gulf of Tonkin Area, and it is hoped that similar steps
will be taken to resolve the issues outstanding in the South China Sea.
Exploration activities in the area will be subject to the resolution of the
disputes. The Company has recorded no reserves attributable to this petroleum
contract.
DRILLING AND DEVELOPMENT ACTIVITY
Due to the sovereignty issues, the Company has been unable to pursue an
aggressive exploration program during phase one of the contract. As a result,
extensions have been obtained by the Company, with the current extension in
effect until June 2001. China and Vietnam are now engaged in discussions to
resolve the territorial dispute, although there is no certainty of timing or the
outcome of such discussions. The Company plans to acquire a 7,705-mile 2-D
seismic survey covering the entire block. This seismic survey will cost an
estimated $8 million and will enable a full evaluation of the potential for
hydrocarbon traps in advance of committing to the next phase. The petroleum
contract provides that once phase one is complete, an optional phase two may be
entered upon relinquishment of 25% of the block. The phase two exploration
commitment consists of an exploratory well drilled to 6,562 feet (2,000 meters)
for a minimum commitment of $2 million followed by a 10% relinquishment within
six months of completion of the well.
<PAGE> 12
12
QINGSHUI BLOCK, CHINA
GENERAL
In October 1997, the Company signed a farmout agreement with Shell Exploration
(China) Limited, ("Shell"), whereby the Company acquired a 50% participation
interest in Shell's Liaohe area onshore exploration project in northeast China.
Shell had 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
provided for a three-phase exploration program. Shell was the operator of the
project.
Pursuant to the petroleum contract, the first exploration period commenced
November 1, 1996. Pursuant to the terms of the contract, a nine-month study
phase required a work commitment to evaluate the deep potential of the block,
with an expected minimum expenditure of $3 million. During the remainder of the
first exploration phase and prior to November 1, 1999, Shell was required to
drill and complete one exploratory well to a depth of 4,500 meters, with a
minimum expenditure of $8 million.
Pursuant to the farmout agreement between Shell and the Company, the Company
would earn 50% of Shell's working interest in the block. In July 1998, the
Company paid to Shell 50% of Shell's prior investment in the Block, which was
approximately $4 million ($2 million to the Company). In addition, the Company
agreed to pay 100% of the first $8 million of the costs for the phase one
exploration period.
DRILLING AND DEVELOPMENT ACTIVITY
During 1999, the first exploratory well on the Qingshui Block was drilled to a
total depth of 4,500 meters, and two reservoirs, the Sha-2 and Sha-3, were
tested. Although hydrocarbons were encountered during drilling of the Qing Deep
22, Benton and operator Shell concluded in the third quarter of 1999 that the
well was non-commercial. As a result, the Company elected not to continue to the
second exploration phase and has relinquished its interest in the Block.
Accordingly, the Company recognized a write-down of the capitalized cost related
to the farmout agreement of $12.6 million in the third quarter of 1999.
SANTA BARBARA COUNTY, CALIFORNIA
GENERAL
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases ("California Leases") from Molino
Energy Company, LLC ("Molino Energy"), which held 100% of these leases. The
project area covers the Molino, Gaviota and Caliente Fields, located
approximately 35 miles west of Santa Barbara, California. In consideration of
the 40% participation interest in the California Leases, the Company became the
operator of the project and paid 100% of the first $3.7 million and 53% of the
remainder of the costs of the first well drilled on the block.
LOCATION AND GEOLOGY
The Company's operating interest covers three known fields located on three
adjacent state oil and gas leases off the central California coast. Each of
these leases covers approximately 4,000 acres. The Molino, Gaviota and Caliente
Fields have produced an aggregate of 363 Bcf of natural gas from subsea
completion in the Vaqueros formation, and the deeper, Sacate/Matilija formation
has produced 12 Bcf of natural gas from the Molino Field. In addition, the
Monterey formation has been penetrated from all of the gas wells, but has never
been produced. The onshore drill site has immediate access to oil and gas
pipelines.
DRILLING AND DEVELOPMENT ACTIVITY
During 1998, the 2199 #7 exploratory well was drilled to the Gaviota anticline.
Drill stem tests proved to be inconclusive or non-commercial, and the well was
temporarily abandoned for further evaluation. In November 1998, the Company
entered into an agreement to acquire Molino Energy's interest in the California
Leases in exchange for the release of its joint interest billing obligations,
but the transaction has not yet been finalized. In the fourth quarter of 1999,
the Company decided to focus its capital expenditures on existing producing
properties and fulfilling work commitments associated with its other properties.
Because the Company currently has no firm approved plans to continue drilling on
the California Leases and the 2199 #7 exploratory well did not result in
commercial reserves, the Company wrote off all of the capitalized costs
associated with the California Leases of $9.2 million and the joint interest
receivable of $3.1 million due from Molino Energy at December 31, 1999.
<PAGE> 13
13
SIRHAN BLOCK, JORDAN
GENERAL
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with the Natural Resources Authority of Jordan
("NRA"), established by the Hashemite Kingdom of Jordan, to explore, develop,
and produce the Sirhan block in southeastern Jordan.
Under the terms of the PSA, the Company is obligated to make certain capital and
operating expenditures in a first phase and may elect to continue into
additional phases with minimum commitments as follows: $5.1 million in the first
exploration phase (2 years) to perform geological studies and expenses incurred
in drilling exploratory wells; $8 million in the second exploration phase (3
years) for seismic acquisitions, geological studies, and expenses incurred in
drilling exploratory wells; and $10 million in the third exploration phase (3
years) for seismic acquisitions, geological studies, and expenses incurred in
drilling exploratory wells. If the Company expends more than the minimum
expenditure in one phase, the excess expenditure will be credited against the
Company's minimum expenditure obligation during the next phase. In addition, the
Company will be entitled to recover all operating costs and expenses incurred.
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.
DRILLING AND DEVELOPMENT ACTIVITY
During 1998, the Company reentered two wells and tested two different
reservoirs. The WS-9 well tested significant, but non-commercial amounts of gas;
the WS-10 well resulted in no commercial amounts of hydrocarbons. Therefore, at
December 31, 1998, the Company wrote down $3.7 million in capitalized costs
incurred to date related to the PSA. During 1999, the Company incurred an
additional $0.3 million in capitalized costs, which were written off at December
31, 1999 as a result of the Company's decision to minimize capital expenditures
to those that were necessary in order to maintain currently producing
properties. The Company will continue to reprocess and remap seismic data and
conduct geological studies on the block through May 2000.
SENEGAL, AFRICA
GENERAL
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. The
Company's $5.4 million work commitment on the Thies Block consisted of hooking
up the existing well, drilling two additional wells and constructing a
41-kilometer (approximately 25-mile) gas pipeline to Senegal's main electric
generating facility near Dakar.
Additionally, the Company obtained the exclusive right to evaluate approximately
7.5 million acres of Senegal's entire near-offshore holdings, which have been
partitioned into six separate blocks. This includes the joint area shared
between Senegal and Guinea-Bissau and comprises portions of the Dome Flore
block. The Company was 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.
DRILLING AND DEVELOPMENT ACTIVITY
The Company reprocessed 1,565 kilometers of 2-D seismic data on the Thies Block
prior to making a reinterpretation of the existing discoveries and planning an
exploration program. In the offshore areas, the Company reprocessed and/or
migrated and filtered approximately 32,000 kilometers of 2-D seismic data out of
a total data set in excess of 35,000 kilometers.
In October 1999, the Company entered into an agreement with First Seismic
Corporation ("First Seismic") whereby the Company, upon receiving a release from
Petrosen of its remaining work commitment, transferred its entire working
interests in the Theis Block and paid $0.7 million to First Seismic in exchange
for 135,000 series B preferred shares of First Seismic. The Company performed a
valuation of the securities at the date of the agreement with First Seismic and
concluded that the securities had a de minimis fair value. Accordingly, the
Company has not assigned any cost to the securities. For the year ended December
31, 1999, the Company recorded a write-down of $1.6 million comprised of $0.9
million of previously capitalized costs and $0.7 million of payment to First
Seismic. At December 31, 1999, the Company evaluated the securities and believes
that the fair value of the securities has not changed since the date of the
agreement.
<PAGE> 14
14
In late 1999, the Company elected to not continue with the evaluation of, and
has relinquished its interest in, the near-offshore acreage and, accordingly,
recognized a write-down of the capitalized costs related to the acreage of $1.5
million.
RESERVES
The following table sets forth information regarding estimates of proved
reserves at December 31, 1999 prepared by the Company and audited by Huddleston
& Co., Inc., independent petroleum engineers:
<TABLE>
<CAPTION>
CRUDE OIL AND CONDENSATE (MBBLS)
--------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -----
<S> <C> <C> <C>
Venezuela(1) 53,695 54,274 107,969
Russia(2) 15,120 25,009 40,129
------ ------ -------
Total 68,815 79,283 148,098
====== ====== =======
</TABLE>
(1) Includes reserve information net of a 20% deduction for the minority
interest in Benton-Vinccler. All Venezuelan reserves are attributable
to an operating service agreement between Benton-Vinccler and PDVSA,
under which all mineral rights are owned by the Government of
Venezuela. See "--South Monagas Unit, Venezuela."
(2) Although the Company estimates that there are substantial natural gas
reserves in the North Gubkinskoye Field, no natural gas reserves have
been recorded because of a lack of a ready market.
Estimates of commercially recoverable oil and gas reserves and of the future net
cash flows derived therefrom are based upon a number of variable factors and
assumptions, such as historical production from the subject properties,
comparison with other producing properties, the assumed effects of regulation by
governmental agencies and assumptions concerning future operating costs,
severance and excise taxes, export tariffs, abandonment costs, development costs
and workover and remedial costs, all of which may vary considerably from actual
results. All such estimates are to some degree speculative, and various
classifications of reserves are only attempts to define the degree of
speculation involved. For these reasons, estimates of the commercially
recoverable reserves of oil attributable to any particular property or group of
properties, the classification, cost and risk of recovering such reserves and
estimates of the future net cash flows expected therefrom, prepared by different
engineers or by the same engineers at different times may vary substantially.
The difficulty of making precise estimates is accentuated by the fact that 53%
of the Company's total proved reserves were undeveloped as of December 31, 1999.
Therefore, the Company's actual production, oil sales, severance and excise
taxes, export tariffs, development expenditures, workover and remedial
expenditures, abandonment expenditures and operating expenditures with respect
to its reserves will likely vary from estimates, and such variances may be
material. Reserve estimates are not constrained by the availability of the
capital resources required to finance the estimated development and operating
expenditures.
In addition, actual future net cash flows will be affected by factors such as
actual production, supply and demand for oil, availability and capacity of
gathering systems and pipelines, changes in governmental regulations or taxation
and the impact of inflation on costs. The timing of actual future net oil sales
from proved reserves, and thus their actual present value, can be affected by
the timing of the incurrence of expenditures in connection with development of
oil and gas properties. The 10% discount factor, which is required by the
Securities and Exchange Commission to be used to calculate present value for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
the oil and gas industry. Discounted present value, no matter what discount rate
is used, is materially affected by assumptions as to the amount and timing of
future production, which assumptions may and often do prove to be inaccurate.
For the period ending December 31, 1999, the Company reported $744.9 million of
discounted future net cash flows before income taxes from proved reserves based
on the Commission's required calculations.
<PAGE> 15
15
PRODUCTION, PRICES AND LIFTING COST SUMMARY
The following table sets forth by country net production, average sales prices
and average lifting costs of the Company for the years ended December 31, 1999,
1998 and 1997:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER
---------------------------------------------
1999 1998 1997
------------- ------------- -------------
<S> <C> <C> <C>
VENEZUELA (1)
Net Crude Oil Production (Bbls) 9,666,958 12,172,352 15,394,807
Average Crude Oil Sales Price ($ per Bbl) $ 9.21 $ 6.75 $10.01
Average Lifting Costs ($ per Bbl) $ 4.00 $ 3.21 $2.24
RUSSIA (2)
Net Crude Oil Production (Bbls) 1,451,000 923,602 880,148
Average Crude Oil Sales Price ($ per Bbl) $ 7.59 $ 8.72 $11.28
Average Lifting Costs ($ per Bbl) $ 3.32 $ 6.09 $8.35
</TABLE>
(1) The presentation for Venezuela includes 100% of the production, without
deduction for minority interest.
(2) Geoilbent (34% owned by the Company) and Arctic Gas Company (24% and
10% ownership not subject to certain sale and transfer restrictions at
December 31, 1999 and 1998, respectively), which are accounted for
under the equity method, have been included at their respective
ownership interest in the consolidated financial statements based on a
fiscal period ending September 30 and, accordingly, results of
operations for oil and gas producing activities in Russia reflect the
years ended September 30, 1999, 1998 and 1997 for Geoilbent and the
year ended September 30, 1999 for Arctic Gas.
REGULATION
GENERAL
The Company's operations are affected by political developments and laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and costs. In
any country in which the Company may do business, the oil and gas industry
legislation and agency regulation is periodically changed for a variety of
political, economic, environmental and other reasons. Numerous governmental
departments and agencies issue rules and regulations binding on the oil and gas
industry, some of which carry substantial penalties for the failure to comply.
The regulatory burden on the oil and gas industry increases the Company's cost
of doing business.
VENEZUELA
Venezuela requires environmental and other permits for certain operations
conducted in oil field development, such as site construction, drilling, and
seismic activities. As a contractor to PDVSA, Benton-Vinccler submits capital
and operating budgets to PDVSA for approval. Capital expenditures to comply with
Venezuelan environmental regulations relating to the reinjection of gas in the
field and water disposal were $3.6 million in 1999 and are expected to be $7.7
million in 2000. Benton-Vinccler also submits requests for permits for drilling,
seismic and operating activities to PDVSA, which then obtains such permits from
the Ministry of Energy and Mines and Ministry of Environment, as required.
Benton-Vinccler is also subject to income, municipal and value added taxes, and
must file certain monthly and annual compliance reports to the national tax
administration and to various municipalities.
RUSSIA
Geoilbent submits annual production and development plans, which include
information necessary for permits and approvals for its planned drilling,
seismic and operating activities, to local and regional governments and to the
Ministry of Fuel and Energy, Committee of Geology and Ministry of Economy.
Geoilbent also submits annual production targets and quarterly export
nominations for oil pipeline transportation capacity to the Ministry of Fuel and
Energy. Geoilbent is subject to customs, value added, and municipal and income
taxes. Various municipalities and regional tax inspectorates are involved in the
assessment and collection of these taxes. Geoilbent must file operating and
financial compliance reports with several bodies, including the Ministries of
Fuel and Energy, Committee of Geology, Committee for Technical Mining
Monitoring, the Ministry of Ecology, and the State Customs Committee.
<PAGE> 16
16
DRILLING, ACQUISITION AND FINDING COSTS
During the years ended December 31, 1999, 1998 and 1997, the Company spent
approximately $25 million, $111 million and $109 million, respectively, for
acquisitions of leases and producing properties, development and exploratory
drilling, production facilities and additional development activities such as
workovers and recompletions.
The Company has drilled or participated in the drilling of wells as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------------------
1999 1998 1997
--------------------------- -------------------------- ---------------------------
GROSS NET GROSS NET GROSS NET
------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
WELLS DRILLED:
Exploratory:
Crude oil - - - - - -
Natural gas - - - - - -
Dry holes 3 1.60 - - - -
Development:
Crude oil 28 9.18 46 22.54 31 22.040
Natural gas - - - - - -
Dry holes - - - - 1 .340
------- -------- ------ -------- ------- ---------
TOTAL 31 10.78 46 22.54 32 22.380
======= ======== ====== ======== ======= =========
AVERAGE DEPTH OF WELLS (FEET) 9,092 7,934 6,659
PRODUCING WELLS (1):
Crude Oil 181 108.000 159 97.300 124 78.960
Natural Gas - - - - - -
</TABLE>
(1) The information related to producing wells reflects wells the Company
drilled, wells the Company participated in drilling and producing wells
the Company acquired.
At March 24, 2000, the Company was participating in the drilling of 1 well in
Venezuela and 5 wells in Russia.
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, 1999, the Company added,
net of production and property sales, approximately 171.4 MMBOE of proved
reserves through purchases of reserves-in-place, discoveries of oil and natural
gas reserves, extensions of existing producing fields and revisions of
previously estimated reserves, for which the finding costs were $2.14 per BOE.
The Company's estimate of future development costs for its undeveloped proved
reserves at December 31, 1999 was $1.68 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.
ACREAGE
The following table summarizes the developed and undeveloped acreage owned,
leased or under concession as of December 31, 1999:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------------------ --------------------------------
GROSS NET GROSS NET
-------------- ------------- -------------- --------------
<S> <C> <C> <C> <C>
Venezuela 8,474 6,779 674,664 277,084
Russia 37,980 13,686 1,572,017 742,780
China - - 7,470,080 7,470,080
Jordan - 1,192,752 1,192,752
United States - - 12,340 12,340
-------- -------- ---------- ----------
Total 46,454 20,465 10,921,853 9,695,036
======== ======== ========== ==========
</TABLE>
<PAGE> 17
17
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, 1999, the Company had 63 employees augmented from time to time
with independent consultants, as required. Benton-Vinccler had 155 employees,
Geoilbent 501 employees and Arctic Gas 73 employees.
TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE
All Venezuelan reserves are attributable to an operating service agreement
between Benton-Vinccler and PDVSA, under which all mineral rights are owned by
the Government of Venezuela. With regard to Russian acreage, Geoilbent has
obtained certain documentation from appropriate regulatory bodies in Russia
which the Company believes is adequate to establish Geoilbent's right to
develop, produce and market oil and gas from the North Gubkinskoye Field in
Russia.
The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea,
with an option for another one million acres under certain circumstances, and
lies within an area which is the subject of a territorial dispute between the
People's Republic of China and Vietnam. Vietnam has executed an agreement on a
portion of the same offshore acreage with Conoco Inc. The territorial dispute
has existed for many years, and there has been limited exploration and no
development activity in the area under dispute. It is uncertain when or how this
dispute will be resolved, and under what terms the various countries and parties
to the agreements may participate in the resolution, although certain proposed
economic solutions currently under discussion would result in the Company's
interest being reduced.
At the time of acquisition of undeveloped acreage in the United States, the
Company conducts a limited title investigation. A title opinion from a qualified
law firm is obtained prior to drilling any given U.S. prospect. Title to
presently producing properties is investigated by a qualified law firm prior to
purchase. The Company believes its method of investigating the title to these
domestic properties is consistent with general practices in the oil and gas
industry and is designed to enable the Company to acquire title which is
generally considered to be acceptable in the oil and gas industry.
<PAGE> 18
18
GLOSSARY
When the following terms are used in the text they have the meanings indicated.
MCF. "Mcf" means thousand cubic feet. "Mmcf" means million cubic feet.
"Bcf" means billion cubic feet. "Tcf" means trillion cubic feet.
BBL. "Bbl" means barrel. "Bbls" means barrels. "MBbls" means thousand
barrels. "MMBbls" means million barrels. "BBbls" means billion barrels.
BOE. "BOE" means barrels of oil equivalent, which are determined using the
ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf
of natural gas so that six Mcf of natural gas is referred to as one barrel of
oil equivalent or "BOE". "MBOE" means thousands of barrels of oil equivalent.
"MMBOE" means millions of barrels of oil equivalent.
CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with
exploratory and development drilling (including exploratory dry holes);
leasehold acquisitions; seismic data acquisitions; geological, geophysical and
land-related overhead expenditures; delay rentals; producing property
acquisitions; and other miscellaneous capital expenditures.
COMPLETION COSTS. "Completion Costs" means, as to any well, all those
costs incurred after the decision to complete the well as a producing well.
Generally, these costs include all costs, liabilities and expenses, whether
tangible or intangible, necessary to complete a well and bring it into
production, including installation of service equipment, tanks, and other
materials necessary to enable the well to deliver production.
DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional
well to the same reservoir as other producing wells on a lease, or drilled on an
offset lease not more than one location away from a well producing from the same
reservoir.
EXPLORATORY WELL. An "Exploratory Well" is a well drilled in search of a
new and as yet undiscovered pool of oil or gas, or to extend the known limits of
a field under development.
FINDING COST. "Finding Cost", expressed in dollars per BOE, is calculated
by dividing the amount of total capital expenditures related to acquisitions,
exploration and development costs (reduced by proceeds for any sale of oil and
gas properties) by the amount of total net reserves added or reduced as a result
of property acquisitions and sales, drilling activities and reserve revisions
during the same period.
FUTURE DEVELOPMENT COST. "Future Development Cost" of proved nonproducing
reserves, expressed in dollars per BOE, is calculated by dividing the amount of
future capital expenditures related to development properties by the amount of
total proved non-producing reserves associated with such activities.
GROSS ACRES OR WELLS. "Gross Acres or Wells" are the total acres or wells,
as the case may be, in which an entity has an interest, either directly or
through an affiliate.
LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a
producing formation to the surface, consisting of the costs incurred to operate
and maintain wells and related equipment and facilities, including labor costs,
repair and maintenance, supplies, insurance, production, severance and windfall
profit taxes.
NET ACRES OR WELLS. A party's "Net Acres" or "Net Wells" are calculated by
multiplying the number of gross acres of gross wells in which that party has an
interest by the fractional interest of the party in each such acre or well.
PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved
Developed Reserves expected to be produced from existing completion intervals
now open for production in existing wells. "Producing Properties" are properties
to which Producing Reserves have been assigned by an independent petroleum
engineer.
<PAGE> 19
19
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 oil sales from Proved Reserves are estimated assuming
that oil and gas prices and production costs remain constant. The resulting
stream of oil sales is then discounted at the rate of 10% per year to obtain a
present value.
3-D SEISMIC. "3-D Seismic" is the method by which a three dimensional
image of the earth's subsurface is created through the interpretation of seismic
data. 3-D surveys allow for a more detailed understanding of the subsurface than
do conventional surveys and contribute significantly to field appraisal,
development and production.
UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and gas acreage on which
wells have not been drilled or completed to a point that would permit commercial
production regardless of whether such acres contain proved reserves.
ITEM 2. PROPERTIES
The Company has entered into a 15-year lease agreement for office space in
Carpinteria, California. The Company has leased 50,000 square feet for
approximately $74,000 per month with annual rent adjustments based on certain
changes in the Consumer Price Index. The Company has entered into a sublease
agreement for the office space that will not be immediately needed for
operations. The Company has also entered into a sublease agreement for the
office space that it previously occupied. Rents for the subleases approximate
the Company's lease costs of these facilities. For information concerning the
location and character of the Company's oil and gas properties and interests,
see Item 1.
ITEM 3. LEGAL PROCEEDINGS
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties, and that it paid a
price in excess of the fair value of the property. A trial date has been
scheduled for April 25, 2000 and discovery is complete, unless reopened by the
court. The Company intends to vigorously contest the suit, and in management's
opinion it is too early to assess the probability of an unfavorable outcome.
In 1996, 1997 and November 1998, the Company made certain unsecured loans to its
then-Chief Executive Officer, A. E. Benton. Each of these loans was evidenced by
a promissory note bearing interest at the rate of 6% per annum. At December 31,
1997 and September 30, 1998, the aggregate outstanding amounts of the loans were
$2.0 million and $4.4 million, respectively. In the fourth quarter of 1998, the
Company loaned Mr. Benton an additional $1.1 million to enable him to pay in
full certain margin account obligations owed to third parties which had obtained
a pledge from Mr. Benton of his shares of Company stock. The Company then
obtained a security interest in those shares of stock, certain personal real
estate and proceeds from certain contractual and stock option
<PAGE> 20
20
agreements. At December 31, 1998, the $5.5 million owed to the Company by Mr.
Benton exceeded the value of the Company's collateral, due to the decline in the
price of the Company's stock. As a result, the Company recorded an allowance for
doubtful accounts of $2.9 million. The portion of the note secured by the
Company's stock and stock options, $2.1 million, was presented on the Balance
Sheet as a reduction from Stockhoders' Equity at December 31, 1998. In August
1999, Mr. Benton filed a Chapter 11 (reorganization) bankruptcy petition in the
U.S. Bankruptcy Court for the Central District of California, in Santa Barbara,
California. The Company recorded an additional $2.8 million allowance for
doubtful accounts for the remaining principal and accrued interest owed to the
Company at June 30, 1999, and continues to record additional allowances as
interest accrues ($0.2 million for the period July 1, 1999 to December 31,
1999). Measuring the amount of the allowances requires judgements and estimates,
and the amount eventually realized may differ from the estimate.
In February 2000, the Company entered into a Separation Agreement and a
Consulting Agreement with Mr. Benton, pursuant to which the Company retained Mr.
Benton as an independent contractor to perform certain services for the Company.
At the same time, Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the full repayment of the Company's loans to
Mr. Benton, including all principal and accrued and accruing interest at the
rate of 6% per annum. Under the proposed plan, which the Company anticipates
will be submitted to the bankruptcy court in the second quarter of 2000, the
Company will retain its security interest in Mr. Benton's 600,000 shares of the
Company's stock and in his stock options, and in a portion of certain proceeds
of his Consulting Agreement. Repayment of the Company's loans to Mr. Benton will
be achieved through Mr. Benton's liquidation of certain real and personal
property assets; a phased liquidation of Company stock resulting from Mr.
Benton's exercise of his Company stock options; and, if necessary, from the
retained interest in the portion of the Consulting Agreement's proceeds. The
amount eventually realized by the Company and the timing of its receipt of
payments will depend upon the timing and results of the liquidation of Mr.
Benton's assets.
In the normal course of the Company's business, there are various other legal
proceedings outstanding. In the opinion of management, these proceedings will
not have a material adverse effect on the Company's financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the three month period ended December 31, 1999, no matter was submitted
to a vote of security holders.
<PAGE> 21
21
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 has traded on the New York Stock Exchange ("NYSE")
since April 29, 1997 under the symbol "BNO." As of December 31, 1999, there were
29,576,966 shares of Common Stock outstanding held of record by approximately
1,025 stockholders. The following table sets forth the high and low sales prices
for the Company's Common Stock reported by the NYSE.
YEAR QUARTER HIGH LOW
------ ------------------- ------ -----
1998
First quarter $13.69 $9.75
Second quarter 13.50 7.38
Third quarter 10.75 4.69
Fourth quarter 6.25 2.44
1999
First quarter 5.19 1.94
Second quarter 4.38 1.88
Third quarter 3.13 1.50
Fourth quarter 2.75 1.44
On March 24, 2000, the last sales price for the Common Stock as reported by NYSE
was $3.00 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> 22
22
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA (2)
The following selected consolidated financial data for the Company for each of
the five years in the period ended December 31, 1999, 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,
---------------------------------------------------------------
1999 1998 1997 1996 1995
--------- --------- -------- -------- -------
(amounts in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS:
Total revenues, other income and equity earnings $ 101,959 $ 92,899 $167,818 $154,096 $59,684
Operating expenses 39,393 40,066 35,184 18,255 7,925
Depletion, depreciation and amortization 16,519 33,157 44,513 31,778 15,898
Write-down of oil and gas properties and impairments 25,891 193,893 -- -- --
General and administrative expense 25,969 21,485 17,676 15,268 7,840
Taxes other than on income 3,201 3,177 4,724 2,487 1,018
Interest expense 29,247 32,007 24,082 15,578 7,296
Partnership exchange expenses -- -- -- 2,140 --
Litigation settlement expenses -- -- -- -- 1,673
--------- --------- -------- -------- -------
Income (loss) before income taxes, minority
interest and extraordinary charge (38,261) (230,886) 41,639 68,590 18,034
Income tax expense (benefit) (6,914) (24,411) 17,257 20,249 2,139
--------- --------- -------- -------- -------
Income (loss) before minority interest and
extraordinary charge (31,347) (206,475) 24,382 48,341 15,895
Minority interest 937 (22,895) 6,333 9,984 5,304
--------- --------- -------- -------- -------
Income (loss) before extraordinary charge (32,284) (183,580) 18,049 38,357 10,591
Extraordinary charge for early retirement of
debt, net of tax benefit of $879 -- -- -- 10,075 --
--------- --------- -------- -------- -------
Net income (loss) $ (32,284) $(183,580) $ 18,049 $ 28,282 $10,591
========= ========= ======== ======== =======
Net income (loss) per common share:
Basic:
Income (loss) before extraordinary
charge $ (1.09) $ (6.21) $ 0.62 $ 1.42 $ 0.42
Extraordinary charge -- -- -- 0.38 --
--------- --------- -------- -------- -------
Net income (loss) $ (1.09) $ (6.21) $ 0.62 $ 1.04 $ 0.42
========= ========= ======== ======== =======
Diluted:
Income (loss) before extraordinary
charge $ (1.09) $ (6.21) $ 0.59 $ 1.29 $ 0.40
Extraordinary charge -- -- -- 0.34 --
--------- --------- -------- -------- -------
Net income (loss) $ (1.09) $ (6.21) $ 0.59 $ 0.95 $ 0.40
========= ========= ======== ======== =======
Weighted average common shares outstanding
Basic 29,577 29,554 29,119 27,088 25,084
Diluted 29,577 29,554 30,834 29,813 26,673
</TABLE>
<TABLE>
<CAPTION>
AT DECEMBER 31,
---------------------------------------------------------------
1999 1998 1997 1996 1995
--------- --------- -------- -------- -------
BALANCE SHEET DATA: (amounts in thousands)
<S> <C> <C> <C> <C> <C>
Working capital $32,093 $60,927 $174,759 $106,051 $ 949
Total assets 276,311 324,363 573,599 425,810 208,478
Long-term obligation, net of current portion 264,575 280,002 280,016 175,028 49,486
Stockholders' equity (deficit) (1) (17,178) 12,989 197,732 174,899 103,681
</TABLE>
(1) No cash dividends were paid during any period presented.
(2) As discussed in Note 1 to the Financial Statements, the Company changed
its method of reporting its investment in Geoilbent.
<PAGE> 23
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
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. Geoilbent and Arctic Gas have been included in
the consolidated financial statements based on a fiscal period ending September
30. Results of operations for Geoilbent reflect the twelve months ended
September 30, 1997, 1998 and 1999 and the results of operations for Arctic Gas
reflect the twelve months ended September 30, 1999. The Company's investment in
Geoilbent and Arctic Gas is accounted for using the equity method. Oil and gas
reserve information reflects the Company's 34% ownership interest of Geoilbent
and its unrestricted 24% ownership interest of Arctic Gas.
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all acquisition, exploration,
and development costs incurred. The Company accounts for its oil and gas
properties using cost centers on a country by country basis. Proceeds from sales
of oil and gas properties are credited to the full-cost pools. Capitalized costs
of oil and gas properties are amortized within the cost centers on an overall
unit-of-production method using proved oil and gas reserves as audited by
independent petroleum engineers. Costs amortized include all capitalized costs
(less accumulated amortization and impairment), the estimated future
expenditures (based on current costs) to be incurred in developing proved
reserves, and estimated dismantlement, restoration and abandonment costs (see
Note 1 of Notes to the Consolidated Financial Statements).
Statement of Financial Accounting Standards No. 133 ("SFAS 133"), as amended,
establishes accounting and reporting standards for derivative instruments and
hedging activities. The Company has not used derivative or hedging instruments
since 1996, but may consider hedging some portion of its oil production in the
future. The Company does not believe, however, that the adoption of SFAS 133
will have a material effect on its results of operations or financial position.
The following discussion of the results of operations and financial condition as
of December 31, 1999 and 1998 and for each of the years in the three year period
ended December 31, 1999, 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, 1999,
reflected the results for Benton-Vinccler, C.A. in Venezuela, which accounted
for 100% of the Company's production and oil sales revenue. As a result of
increases in world crude oil prices which were partially offset by lower
production from the South Monagas Unit, oil sales in Venezuela were 8% higher in
1999 compared to 1998 with a 36% increase in realized fees per Bbl (from $6.75
in 1998 to $9.21 in 1999) and a 21% decrease in oil sales quantities (from
12,172,352 Bbls of oil in 1998 to 9,666,958 Bbls of oil in 1999). Operating
expenses on the South Monagas Unit stabilized during 1999. Additionally, during
1999 the Company recognized $25.9 million in impairment of capitalized costs
associated with exploration activities in California, China, Senegal and Jordan.
The following table presents selected expense items as a percentage of oil
sales:
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Operating expenses 44.2% 48.7% 22.8%
Depletion, depreciation and amortization 18.5 40.3 28.9
General and administrative 29.2 26.1 11.5
Taxes other than on income 3.6 3.9 3.1
Interest 32.8 38.9 15.6
</TABLE>
<PAGE> 24
24
YEARS ENDED DECEMBER 31, 1999 AND 1998
The Company had revenues, other income and equity earnings of $102.0 million for
the year ended December 31, 1999. Expenses incurred during the period consisted
of operating expenses of $39.4 million, depletion, depreciation and amortization
expense of $16.5 million, write-down of oil and gas properties and impairments
of $25.9 million, general and administrative expense of $26.0 million, taxes
other than on income of $3.2 million, interest expense of $29.2 million, income
tax benefit of $6.9 million and a minority interest of $0.9 million. Net loss
for the period was $32.3 million or $1.09 per share (diluted).
By comparison, the Company had revenues, other income and equity earnings of
$92.9 million for the year ended December 31, 1998. Expenses incurred during the
period consisted of operating expenses of $40.1 million, depletion, depreciation
and amortization expense of $33.2 million, write-down of oil and gas properties
and impairments of $193.9 million, general and administrative expense of $21.5
million, taxes other than on income of $3.2 million, interest expense of $32.0
million, income tax benefit of $24.4 million and a minority interest reduction
of $22.9 million. Net loss for the period was $183.6 million or $6.21 per share
(diluted).
Revenues, other income and equity earnings increased $9.1 million, or 10%,
during the year ended December 31, 1999 compared to the corresponding period of
1998 primarily due to increased oil sales revenue in Venezuela as a result of
increases in world crude oil prices substantially offset by a 21% decrease in
oil sales quantities. Sales quantities for the year ended December 31, 1999 from
Venezuela were 9,666,958 Bbls compared to 12,172,352 Bbls for the year ended
December 31, 1998. Prices for crude oil per Bbl averaged $9.21 (pursuant to
terms of an operating service agreement) from Venezuela for the year ended
December 31, 1999 compared to $6.75 for the year ended December 31, 1998.
Investment earnings and other decreased $5.0 million in 1999 compared to 1998
primarily due to a reduction in marketable securities in 1999. Revenues, other
income and equity earnings were increased by the equity in earnings of
affiliated companies of $2.9 million in 1999 compared to equity in losses of
affiliated companies of $5.1 million in 1998.
Operating expenses decreased $0.7 million, or 2%, during the year ended December
31, 1999 compared to 1998 primarily due to a stabilization of operating expenses
in Venezuela. Depletion, depreciation and amortization decreased $16.7 million,
or 50%, during the year ended December 31, 1999 compared to the corresponding
period of 1998 primarily due to write-downs of oil and gas properties in
Venezuela in 1998. Depletion expense per BOE produced from Venezuela during the
year ended December 31, 1999 was $1.53 compared to $2.62 during the previous
year. Additionally, the Company recognized $25.9 million of impairment expense
in 1999 associated with exploration activities in California, China, Senegal and
Jordan. General and administrative expenses increased $4.5 million, or 21%,
during the year ended December 31, 1999 compared to 1998 primarily due to costs
associated with the Company's reduction in force, increased consulting and legal
fees, the write off of the joint interest receivable of $3.1 million due from
Molino Energy at December 31, 1999 associated with the California Leases and an
allowance for doubtful accounts related to amounts owed to the Company by its
former Chief Executive Officer (see Note 15 of Notes to the Consolidated
Financial Statements). Taxes other than on income were unchanged in 1999
compared to 1998. Interest expense decreased $2.8 million, or 9%, in 1999
compared to 1998 primarily due to capitalized interest. Income tax benefit
decreased $17.5 million, or 72%, during the year ended December 31, 1999
compared to 1998 primarily due to increased taxable income in Venezuela. The net
income attributable to the minority interest increased $23.8 million, or 104%,
for 1999 compared to 1998 as a result of the increased profitability of
Benton-Vinccler's operations in Venezuela.
In an effort to reduce general and administrative expenses, the Company reduced
its administrative and technical staff in Carpinteria by 10 persons in October
1999. In connection with the reduction in staff, the Company recorded
termination benefits expense of $0.8 million that are payable from October 1999
through September 2000. The unpaid portion of these benefits of $0.4 million is
included in Accrued Expenses at December 31, 1999. As a result of these
reductions, the Company anticipates reduced annual employee costs of
approximately $1.2 million beginning in the first quarter of 2000.
YEARS ENDED DECEMBER 31, 1998 AND 1997
The Company had revenues, other income and equity earnings of $92.9 million for
the year ended December 31, 1998. Expenses incurred during the period consisted
of operating expenses of $40.1 million, depletion, depreciation and amortization
expense of $33.2 million, write-down of oil and gas properties and impairments
of $193.9 million, general and administrative expense of $21.5 million, taxes
other than on income of $3.2 million, interest expense of $32.0 million, income
tax benefit of $24.4 million and a minority interest reduction of $22.9 million.
Net loss for the period was $183.6 million or $6.21 per share (diluted).
By comparison, the Company had revenues, other income and equity earnings of
$167.8 million for the year ended December 31, 1997. Expenses incurred during
the period consisted of operating expenses of $35.2 million, depletion,
depreciation and amortization expense of $44.5 million, general and
administrative expense of $17.7 million, taxes other than on income of $4.7
million, interest expense of $24.1 million, income tax expense of $17.3 million
and a minority interest of $6.3 million. Net income for the period was $18.0
million or $0.59 per share (diluted).
<PAGE> 25
25
Revenues, other income and equity earnings decreased $74.9 million, or 45%,
during the year ended December 31, 1998 compared to the corresponding period of
1997 primarily due to decreased oil sales revenue in Venezuela as a result of
declines in world crude oil prices and a 21% decrease in oil sales quantities
due largely to operational problems with certain high volume wells. Sales
quantities for the year ended December 31, 1998 from Venezuela were 12,172,352
Bbls compared to 15,394,807 Bbls for the year ended December 31, 1997. Prices
for crude oil per Bbl averaged $6.75 (pursuant to terms of an operating service
agreement) from Venezuela for the year ended December 31, 1998 compared to
$10.01 for the year ended December 31, 1997. Revenues, other income and equity
earnings for 1998 were decreased by the equity in losses of affiliated companies
of $5.1 million compared to equity in losses of affiliated companies of $0.8
million in 1997.
Operating expenses increased $4.9 million, or 14%, during the year ended
December 31, 1998 compared to 1997 primarily due to continuing maturation of the
Uracoa oil field in Venezuela resulting in higher water handling, gas handling,
workover, transportation and chemical costs. The increase was partially offset
by reduced oil production in Venezuela. Depletion, depreciation and amortization
decreased $11.3 million, or 25%, during the year ended December 31, 1998
compared to the corresponding period of 1997 primarily due to write-downs of oil
and gas properties and reduced oil sales in Venezuela in 1998, partially offset
by increased capital requirements in Venezuela. Depletion expense per BOE
produced from Venezuela during the year ended December 31, 1998 was $2.62
compared to $2.83 during the previous year. Additionally, the Company recognized
write-downs of oil and gas properties during 1998 in the Venezuela cost center
of $187.8 million pursuant to the ceiling limitation prescribed by the full cost
method of accounting. The write-downs were a result of the effect of declines in
world crude oil prices on the prices realized by the Company for its Venezuelan
oil sales. The Company also recognized $6.1 million of impairment expense
associated with certain exploration activities. General and administrative
expenses increased $3.8 million, or 21%, during the year ended December 31, 1998
compared to 1997 primarily due to an allowance for doubtful accounts related to
amounts owed to the Company by its former Chief Executive Officer (see Note 15
of Notes to the Consolidated Financial Statements) and costs incurred in the
Company's China operation. Taxes other than on income decreased $1.5 million, or
32%, during the year ended December 31, 1998 compared to 1997 primarily due to
decreased Venezuelan municipal taxes which are a function of oil sales. Interest
expense increased $7.9 million, or 33%, in 1998 compared to 1997 primarily due
to the issuance of $115 million in senior unsecured notes in November 1997.
Income tax expense decreased $41.7 million, or 241%, during the year ended
December 31, 1998 compared to 1997 primarily due to decreased taxable income in
Venezuela as a result of write-downs of oil and gas properties. The net income
attributable to the minority interest decreased $29.2 million, or 463%, for 1998
compared to 1997 as a result of the decreased profitability of Benton-Vinccler's
operations in Venezuela.
YEARS ENDED DECEMBER 31, 1997 AND 1996
The Company had revenues, other income and equity earnings of $167.8 million for
the year ended December 31, 1997. Expenses incurred during the period consisted
of operating expenses of $35.2 million, depletion, depreciation and amortization
expense of $44.5 million, general and administrative expense of $17.7 million,
taxes other than on income of $4.7 million, interest expense of $24.1 million,
income tax expense of $17.3 million and a minority interest of $6.3 million. Net
income for the period was $18.0 million or $0.59 per share (diluted).
By comparison, the Company had revenues, other income and equity earnings of
$154.1 million for the year ended December 31, 1996. Expenses incurred during
the period consisted of operating expenses of $18.3 million, depletion,
depreciation and amortization expense of $31.8 million, general and
administrative expense of $15.3 million, taxes other than on income of $2.5
million, interest expense of $15.6 million, partnership exchange expense of $2.1
million, income tax expense of $20.2 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, other income and equity earnings increased $13.7 million, or 9%,
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 15,394,807 Bbls
compared to 12,647,987 Bbls 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 for the year ended December 31, 1997 compared to
$10.82 for the year ended December 31, 1996. Revenues, other income and equity
earnings for 1997 were increased by a foreign exchange gain of $2.0 million
compared to a gain of $1.8 million in 1996.
Operating expenses increased $16.9 million, or 92%, 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 $12.7 million, or 40%, during the year ended December 31, 1997
compared to the corresponding period in 1996. Depletion expense per BOE produced
from Venezuela during the year ended December 31, 1997 was $2.83 compared to
$2.33 during the previous year.
<PAGE> 26
26
General and administrative expenses increased $2.4 million, or 16% 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. Taxes other than on income increased $2.2 million, or 88%, during the
year ended December 31, 1997 compared to 1996 primarily due to increased
Venezuelan municipal taxes which are a function of oil sales. Interest expense
increased $8.5 million, or 54%, 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 $2.9 million, or 14%, during the year ended December 31, 1997
compared to 1996 primarily due to decreased taxable income in Venezuela. The net
income attributable to the minority interest decreased $3.7 million, or 37%, for
1997 compared to 1996 as a result of the decreased profitability of
Benton-Vinccler's operations in Venezuela.
DOMESTIC OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases ("California Leases") from Molino
Energy Company, LLC ("Molino Energy"), which held 100% of these leases. The
project area covers the Molino, Gaviota and Caliente Fields, located
approximately 35 miles west of Santa Barbara, California. In consideration of
the 40% participation interest in the California Leases, the Company became the
operator of the project and paid 100% of the first $3.7 million and 53% of the
remainder of the costs of the first well drilled on the block. During 1998, the
2199 #7 exploratory well was drilled to the Gaviota anticline. Drill stem tests
proved to be inconclusive or non-commercial, and the well was temporarily
abandoned for further evaluation. In November 1998, the Company entered into an
agreement to acquire Molino Energy's interest in the California Leases in
exchange for the release of its joint interest billing obligations, but the
transaction has not yet been finalized. In the fourth quarter of 1999, the
Company decided to focus its capital expenditures on existing producing
properties and fulfilling work commitments associated with its other properties.
Because the Company currently has no firm approved plans to continue drilling on
the California Leases and the 2199 #7 exploratory well did not result in
commercial reserves, the Company wrote off all of the capitalized costs
associated with the California Leases of $9.2 million and the joint interest
receivable of $3.1 million due from Molino Energy at December 31, 1999.
INTERNATIONAL OPERATIONS
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%. However, Benton-Vinccler reported significantly lower effective tax
rates for 1998 due to the effect of the devaluation of the Bolivar while
Benton-Vinccler uses the U.S dollar as its functional currency. The effective
tax rate for 1999 was lower due to a decrease in the valuation allowance. The
Company cannot predict the timing or impact of future devaluations in Venezuela.
A 3-D seismic survey has been conducted over the southwestern portion of, and a
371 kilometer 2-D seismic survey has been acquired for, the Delta Centro Block
in Venezuela. During 1999, the Block's first exploration well, the Jarina 1-X,
penetrated a thick potential reservoir sequence, but encountered no commercial
hydrocarbons. The Company and its partners continue to evaluate the remaining
leads on the Block, including their potential reserves and risk factors. The
total cost to the Company of acquiring the seismic data and drilling the Jarina
1-X was $15.2 million. The Company's operations related to Delta Centro will be
subject to oil and gas industry taxation, which currently provides for royalties
of 16.66% and income taxes of 67.7%.
Geoilbent is subject to a statutory income tax rate of 35%. Geoilbent has also
been subject to various other tax burdens, including an oil export tariff which
was terminated effective July 1, 1996. Excise, pipeline and other taxes
(including a new oil export tariff of 15 Euros per ton ($1.97 per Bbl)
introduced in 1999) continue to be levied on all oil producers and certain
exporters. The Russian regulatory environment continues to be volatile, and the
Company is unable to predict the impact of taxes, duties and other burdens for
the future.
In December 1996, the Company acquired Benton Offshore China Company, a
privately held company headquartered in Denver, Colorado. Benton Offshore China
Company's principal asset is a petroleum contract with CNOOC for an area known
as Wan'An Bei, WAB-21. The WAB-21 petroleum contract covers 6.2 million acres in
the South China Sea, with an option for another one million acres under certain
circumstances, and lies within an area which is the subject of a territorial
dispute between the People's Republic of China and Vietnam. Vietnam has also
executed an agreement on a portion of the same offshore acreage with Conoco Inc.
The territorial dispute has existed for many years, and there has been limited
exploration and no development activity in the area under dispute. It is
uncertain when or how this dispute will be resolved, and under what terms the
various countries and parties to the agreements may participate in the
resolution, although certain proposed economic solutions currently under
discussion would result in the Company's interest being reduced. Benton Offshore
China Company has submitted plans and budgets to CNOOC for an initial seismic
program to survey the area. However, exploration activities will be subject to
resolution of such territorial dispute. At December 31, 1999, the Company has
recorded no proved reserves attributable to this petroleum contract.
<PAGE> 27
27
In August 1997, the Company acquired the rights to a PSA with Jordan's NRA to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which is expected to last
approximately two years.
In October 1997, the Company signed a farmout agreement with Shell whereby the
Company would acquire a 50% participation interest in Shell's Liaohe area
onshore exploration project in northeast China. Shell held a petroleum contract
with China National Petroleum Corporation to explore and develop the deep rights
in the Qingshui Block, a 563 square kilometer area (approximately 140,000 acres)
in the delta of the Liaohe River. Shell will be the operator of the project. In
July 1998, the Company paid to Shell 50% of Shell's prior investment in the
Block, which was approximately $4 million ($2 million to the Company). The
Company also paid 100% of the first $8 million of the costs for the phase one
exploration period. During the first quarter of 1999, the first exploratory well
on the Qingshui Block was drilled to a total depth of 4,500 meters, and two
reservoirs, the Sha-2 and Sha-3, were tested. Although hydrocarbons were
encountered during drilling of the Qing Deep 22, Benton and operator Shell
concluded in the third quarter of 1999 that the well was non-commerical.
In December 1997, the Company signed a memorandum of understanding with Petrosen
to receive a minimum 45% working interest in and to operate the approximately
one-million acre onshore Thies Block in western Senegal. In addition, the
Company obtained exclusive rights from Petrosen to evaluate and reprocess
geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea Bissau border in the south. The Company may
also choose certain blocks for further data acquisition and exploration
drilling. The Company's $5.4 million work commitment on the Thies Block, where
Petrosen has recently drilled and completed the Gadiaga #2 discovery well,
consisted of hooking up the existing well, drilling two additional wells and
constructing a 41-kilometer (approximately 25-mile) gas pipeline to Senegal's
main electric generating facility near Dakar. The Company's minimum commitment
related to the offshore blocks involved seismic reprocessing to be followed by
additional data acquisition and drilling at the Company's discretion.
In October 1999, the Company entered into an agreement with First Seismic
Corporation ("First Seismic") whereby the Company, upon receiving a release from
Petrosen of its remaining work commitment, transferred its entire working
interests in the Thies Block and paid $0.7 million to First Seismic in exchange
for 135,000 series B preferred shares of First Seismic. The Company performed a
valuation of the securities at the date of the agreement with First Seismic and
concluded that the securities had a de minimis fair value. Accordingly, the
Company has not assigned any cost to the securities. For the year ended December
31, 1999, the Company recorded a write-down of $1.6 million comprised of $0.9
million of previously capitalized costs and $0.7 million of payment to First
Seismic. At December 31, 1999, the Company evaluated the securities and believes
that the fair value of the securities has not changed since the date of the
agreement.
In April 1998, the Company signed an agreement to earn a 40% equity interest in
Arctic Gas. Arctic Gas owns the exclusive rights to evaluate, develop and
produce the natural gas, condensate, and oil reserves in the Samburg and
Yevo-Yakha License Blocks in West Siberia. The two blocks comprise 837,000 acres
within and adjacent to the Urengoy field, Russia's largest producing natural gas
field. Pursuant to a Cooperation Agreement between the Company and Arctic Gas,
the Company will earn a 40% equity interest in exchange for providing the
initial capital needed to achieve natural gas production. The Company's capital
commitment will be in the form of a $100 million credit facility for the
project, the terms of which have yet to be finalized, which is expected to be
disbursed over the initial two-year development phase. The Company received
voting shares representing a 40% ownership in Arctic Gas that contain
restrictions on their sale and transfer. The Share Disposition Agreement
provides for removal of the restrictions as disbursements are made under the
credit facility. Due to the significant influence it exercises over the
operating and financial policies of Arctic Gas, the Company has accounted for
its interest in Arctic Gas using the equity method. Certain provisions of
Russian corporate law would effectively require minority shareholder consent in
the making of new agreements between the Company and Arctic Gas, or to the
changing of any terms in any existing agreements, including the conditions upon
which the restrictions on the shares could be removed, between the two such as
the Cooperation Agreement and the Share Disposition Agreement.
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 oil sales are based on a fee
adjusted quarterly by the percentage change of a basket of crude oil prices
instead of by absolute dollar changes, which dampens both any upward and
downward effects of changing prices on the Company's Venezuelan oil sales 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 oil sales. Fluctuations in oil and gas prices
may affect the Company's total planned development activities and capital
expenditure program.
<PAGE> 28
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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, a significant majority 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, 1999, the Company realized net foreign
exchange gains, primarily as a result of the decline in the value of the
Venezuelan bolivar and the Russian ruble during periods when the Company's
Venezuela-related subsidiaries and Geoilbent had substantial net monetary
liabilities denominated in bolivares and rubles. During the year ended December
31, 1999, the Company's net foreign exchange gains attributable to its
Venezuelan and Russian operations were $1.0 million and $0.7 million,
respectively. However, there are many factors affecting foreign exchange rates
and resulting exchange gains and losses, many of which are beyond the control of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the U.S. dollar. It is not possible to predict the extent
to which the Company may be affected by future changes in exchange rates and
exchange controls.
The Company's operations are affected by political developments and laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and results.
CAPITAL RESOURCES AND LIQUIDITY
The oil and gas industry is a highly capital intensive business. The Company
requires capital principally to fund the following costs: (i) drilling and
completion costs of wells and the cost of production and transportation
facilities; (ii) geological, geophysical and seismic costs; and (iii)
acquisition of interests in oil and gas properties. The amount of available
capital will affect the scope of the Company's operations and the rate of its
growth.
The net funds raised and/or used in each of the operating, investing and
financing activities for each of the years ended December 31, are summarized in
the following table and discussed in further detail below:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
(IN THOUSANDS)
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Net cash provided by (used in) operating activities $ (1,392) $ 2,156 $ 91,966
Net cash provided by (used in) investing activities 20,989 4,134 (212,694)
Net cash provided by (used in) financing activities (15,648) (823) 100,671
-------- ------- --------
Net increase (decrease) in cash $ 3,949 $ 5,467 $(20,057)
======== ======== ========
</TABLE>
At December 31, 1999, the Company had current assets of $59.6 million and
current liabilities of $27.5 million, resulting in working capital of $32.1
million and current ratio of 2.17:1. This compares to the Company's working
capital of $60.9 million and a current ratio of 2.97:1 at December 31, 1998. The
decrease in working capital of $28.8 million was primarily due to capital
expenditures at the South Monagas Unit in Venezuela, exploratory drilling and
development costs in Venezuela, exploratory drilling costs in China and
additional investments in and advances to Arctic Gas Company during 1999.
CASH FLOW FROM OPERATING ACTIVITIES. During 1999, net cash used in operating
activities was approximately $1.4 million, and during 1998 and 1997, net cash
provided by operating activities was approximately $2.2 million and $92.0
million, respectively. Cash flow from operating activities decreased by $3.6
million in 1999 due primarily to reduced collections of accrued oil sales. Cash
flow from operating activities decreased by $89.8 million in 1998 primarily due
to decreased oil sales from Venezuela as a result of declines in world crude oil
prices and reduced sales quantities.
<PAGE> 29
29
CASH FLOW FROM INVESTING ACTIVITIES. During 1999, 1998 and 1997, the Company had
drilling and production related capital expenditures of approximately $37.0
million, $101.9 million and $106.2 million, respectively. Of the 1999
expenditures, $18.8 million was attributable to the development of the South
Monagas Unit in Venezuela, $0.7 million related to the development of the
Gaviota lease in Santa Barbara County, California, $7.0 million related to
drilling costs on the Delta Centro Block in Venezuela, $8.4 million related to
drilling costs on the Qingshui Block in China, $0.3 million related to the
development of the Sirhan Block in Jordan and $1.8 million was attributable to
other projects.
In August 1999, Benton-Vinccler sold its recently-constructed power generation
facility located in the Uracoa field of the South Monagas Unit in Venezuela for
$15.1 million. Concurrently with the sale, Benton-Vinccler entered into a
long-term power purchase agreement with the purchaser of the facility to provide
for the electrical needs of the field throughout the remaining term of the
operating service agreement. The cost of electricity to be provided under terms
of the power purchase agreement approximates that previously paid by
Benton-Vinccler to local utilities. Benton-Vinccler used the proceeds from the
sale to repay indebtedness that is collateralized by a time deposit of the
Company. Permanent repayment of a portion of the loan allowed the Company to
reduce the cash collateral for the loan thereby making such cash available for
working capital needs.
As a result of the decline in oil prices, the Company instituted in 1998, and
continued in 1999, a capital expenditure program to reduce expenditures to those
that the Company believed were necessary to maintain current producing
properties. In the second half of 1999 oil prices recovered substantially. In
December 1999, the Company entered into incentive-based development alliance
agreements with Schlumberger and Helmerich & Payne as part of its plans to
resume development of the South Monagas Unit in Venezuela.
The Company expects its 2000 capital expenditures to be approximately $72-78
million. The Company continually assesses its 2000 capital expenditure program
in view of its financial resources and of industry and commodity price changes.
Its total 2000 capital expenditure requirements include approximately $65-70
million at South Monagas Unit and $7-8 million for Arctic Gas. The Company
anticipates that Geoilbent will continue to fund itself through its own cash
flows and credit facilities.
The Company's indentures contain provisions that restrict the manner in which
the Company can invest in certain of its current operations including Geoilbent.
Additionally, the Company anticipates providing or arranging loans of up to $100
million over time to Arctic Gas pursuant to an equity acquisition agreement
signed in April 1998. The Company continues to evaluate funding alternatives for
the loans to Arctic Gas. The Company's remaining capital commitments worldwide
are relatively minimal and for the most part are substantially at the Company's
discretion. The timing and size of the 2000 investments for Arctic Gas are also
substantially under the Company's discretion. The Company believes it has or can
obtain sufficient funding for certain of its expected capital requirements from
working capital and cash flow from operations.
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond the Company's control.
The Company believes its current cash and cash to be provided by operating
activities will be sufficient to meet the Company's liquidity needs for routine
operations and to service its outstanding debt through 2000, including interest
obligations of approximately $29.5 million. However, if the Company's future
cash requirements are greater than its financial resources, the Company intends
to pursue one or more of the following alternatives: reduce its capital,
operating and administrative expenditures, form strategic joint ventures or
alliances with other industry partners, sell property interests, merge or
combine with another entity, or issue debt or equity securities. There can be no
assurance that any of the alternatives will be available on terms acceptable to
the Company.
CASH FLOW FROM FINANCING ACTIVITIES. In May 1996, the Company issued $125
million in 11.625% senior unsecured notes due May 1, 2003. In November 1997, the
Company issued $115 million in 9.375% senior unsecured notes due November 1,
2007, of which the Company subsequently repurchased $10 million at their par
value. Interest on the notes is due May 1st and November 1st of each year. The
indenture agreements provide for certain limitations on liens, additional
indebtedness, certain investment and capital expenditures, dividends, mergers
and sales of assets. At December 31, 1999, the Company was in compliance with
all covenants of the indentures.
<PAGE> 30
30
YEAR 2000 COMPLIANCE
The Company has completed addressing the Year 2000 issue for critical systems
and applications and transitioned from 1999 to the year 2000 with no major
problems reported on any critical system.
The Year 2000 problem concerned the inability of information systems to properly
recognize and process date-sensitive information beyond January 1, 2000. The
Company began a process of assessing its information technology systems in
November 1997. Substantially all of the software used at the Company's home
office was upgraded in 1998 with a year 2000 compliance modification provided by
the software provider at a minimal cost. The Company's Venezuelan and Russian
subsidiaries installed new accounting software as part of a process improvement
initiative begun in 1997. The software programs selected for installation at
each location were Year 2000 compliant. All "mission critical" office business
systems were Year 2000 compliant. A review of the Company's non-financial
software and imbedded chip technology to assess the impact of the Year 2000 on
systems such as plant flow control devices, product measurement and delivery
devices and fire or other disaster-related safety systems was completed in the
third quarter of 1999. All necessary testing and remediation took place prior to
Year 2000.
The Company's total expenditures on its Year 2000 project were less than
$100,000. These expenditures were recorded at the business unit and corporate
level and were funded from cash provided by operating activities.
RISK FACTORS
In addition to the other information set forth elsewhere in this Form 10-K, the
following factors should be carefully considered when evaluating the Company.
OIL PRICE DECLINES AND VOLATILITY COULD ADVERSELY AFFECT THE COMPANY'S REVENUE,
CASH FLOWS AND PROFITABILITY. Prices for oil fluctuate widely. The average price
received by the Company for oil in Venezuela increased from approximately $6.75
per Bbl for the year ended December 31, 1998, to $9.21 per Bbl for the year
ended December 31, 1999. During the same period, the average price received by
the Company for oil in Russia decreased from $8.72 per Bbl to $7.59 per Bbl. The
Company's Venezuelan oil sales are based on a fee adjusted quarterly by the
percentage change of a basket of crude oil prices instead of by absolute dollar
changes, which dampens both any upward and downward effects of changing prices
on the Company's Venezuelan oil sales and cash flows. The Company's revenues,
profitability and future rate of growth depend substantially upon the prevailing
prices of oil. Prices also affect the amount of cash flow available for capital
expenditures and our ability to service our debt. In addition, we may have
ceiling test writedowns when prices decline. Lower prices may also reduce the
amount of oil that the Company can produce economically. The Company cannot
predict future oil prices. Factors that can cause this fluctuation include:
o relatively minor changes in the supply of and demand for oil;
o market uncertainty;
o the level of consumer product demand;
o weather conditions;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political and economic conditions in oil producing countries,
particularly those in the Middle East; and
o overall economic conditions.
THE COMPANY MAY NOT HAVE AVAILABLE FUNDING TO EXECUTE ITS DRILLING PROGRAMS. The
Company has historically addressed its long-term liquidity needs through the
issuance of debt and equity securities and the use of cash provided by operating
activities. The Company continues to examine the following alternative sources
of long-term capital:
o sales of properties;
o joint venture financing;
o the issuance of nonrecourse production-based financing;
o the sale of common stock, preferred stock or other equity
securities;
o bank borrowings or the issuance of debt securities;
o sales of prospects and technical information.
The availability of these sources of capital will depend upon a number of
factors, some of which are beyond the Company's control. These factors include
general economic and financial market conditions, oil prices and the value and
performance of the Company. The Company may be unable to execute its planned
drilling program if it cannot obtain capital from these sources.
ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE. This
Form 10-K contains estimates of the Company's proved oil and gas reserves and
the estimated future net revenues from such reserves. These
<PAGE> 31
31
estimates are based upon various assumptions, including assumptions required by
the Securities and Exchange Commission relating to oil and gas prices, drilling
and operating expenses, capital expenditures, taxes and availability of funds.
The process of estimating oil and gas reserves is complex. Such process requires
significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. Therefore, these
estimates are inherently imprecise. Actual future production, oil and gas
prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable oil and gas reserves most likely will vary from those
estimated. Any significant variance could materially affect the estimated
quantities and present value of reserves set forth. In addition, the Company may
adjust estimates of proved reserves to reflect production history, results of
exploration and development, prevailing oil and gas prices and other factors,
many of which are beyond its control. Actual production, revenue, taxes,
development expenditures and operating expenses with respect to the Company's
reserves will likely vary from the estimates used. Such variances may be
material.
At December 31, 1999, approximately 53% of the Company's estimated proved
reserves were undeveloped. Undeveloped reserves, by their nature, are less
certain. Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The estimates of the Company's
future reserves include the assumption that it will make significant capital
expenditures to develop these reserves. Although the Company has prepared
estimates of its oil and gas reserves and the costs associated with these
reserves in accordance with industry standards, the Company cannot assure you
that the estimated costs are accurate, that development will occur as scheduled
or that the results will be as estimated. See Supplemental Information on Oil
and Gas Producing Activities.
You should not assume that the present value of future net revenues referred to
is the current market value of the Company's estimated oil and gas reserves. In
accordance with Securities and Exchange Commission requirements, the estimated
discounted future net cash flows from proved reserves are generally based on
prices and costs as of the date of the estimate. Actual future prices and costs
may be materially higher or lower than the prices and costs as of the date of
the estimate. Any changes in consumption or in governmental regulations or
taxation will also affect actual future net cash flows. The timing of both the
production and the expenses from the development and production of oil and gas
properties will affect the timing of actual future net cash flows from estimated
proved reserves and their present value. In addition, the 10% discount factor,
which is required by the Securities and Exchange Commission to be used in
calculating discounted future net cash flows for reporting purposes, is not
necessarily the most accurate discount factor. The effective interest rate at
various times and the risks associated with the Company or the oil and gas
industry in general will affect the accuracy of the 10% discount factor.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS. As of December 31, 1999, the
Company's long-term debt was approximately $265 million. The Company's long-term
debt represented 107% of its total capitalization at December 31, 1999. The
Company's level of debt affects its operations in several important ways,
including the following:
o a significant portion of the Company's cash flow from operations
is used to pay interest on borrowings;
o the covenants contained in the indentures governing the Company's
debt limit its ability to borrow additional funds or to dispose
of assets;
o the covenants contained in the indentures governing the Company's
debt affect its flexibility in planning for, and reacting to,
changes in business conditions;
o the high level of debt could impair the Company's ability to
obtain additional financing in the future for working capital,
capital expenditures, acquisitions, general corporate or other
purposes; and
o the terms of the indentures governing the Company's debt permit
its creditors to accelerate payments upon an event of default or
a change of control.
A high level of debt increases the risk that the Company may default on its debt
obligations. The Company's ability to meet its debt obligations and to reduce
its level of debt depends on its future performance. General economic conditions
and financial, business and other factors affect the Company's operations and
its future performance. Many of these factors are beyond the Company's control.
If the Company is unable to repay its debt at maturity out of cash on hand, it
could attempt to refinance such debt, or repay such debt with the proceeds of
any equity offering. Factors that will affect the Company's ability to raise
cash through an offering of our capital stock or a refinancing of the Company's
debt include financial market conditions and the Company's value and performance
at the time of such offering or other financing. The Company cannot assure you
that any such offering or refinancing can be successfully completed.
LOWER OIL AND GAS PRICES MAY CAUSE THE COMPANY TO RECORD CEILING LIMITATION
WRITEDOWNS. The Company uses the full cost method of accounting to report its
oil and gas operations. Accordingly, the Company capitalizes the cost to
acquire, explore for and develop oil and gas properties. Under full cost
accounting rules, the net capitalized costs of oil and gas properties may not
exceed a "ceiling limit" which is based upon the present value of estimated
future net cash flows from proved reserves, discounted at 10%, plus the lower of
cost or fair market value of unproved properties. If net capitalized costs of
oil and gas properties exceed the ceiling limit, the Company must charge the
amount of the excess to earnings. This is called a "ceiling limitation
writedown." This charge does not impact cash flow from operating activities, but
does reduce stockholders' equity. The risk that the Company will be required to
write down the carrying value of its oil and gas properties increases when oil
and gas prices are low or
<PAGE> 32
32
volatile. In addition, writedowns may occur if the Company experiences
substantial downward adjustments to its estimated proved reserves. In 1998, the
Company recorded after-tax writedowns of $158.5 million ($187.8 million
pre-tax). In 1999, the Company recorded no ceiling limitation writedowns. The
Company cannot assure you that it will not experience ceiling limitation
writedowns in the future.
THE COMPANY MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES. In general,
the volume of production from oil and gas properties declines as reserves are
depleted. The decline rates depend on reservoir characteristics. The Company's
reserves will decline as they are produced unless the Company acquires
properties with proved reserves or conducts successful exploration and
development activities. The Company's future oil production is highly dependent
upon its level of success in finding or acquiring additional reserves. The
business of exploring for, developing or acquiring reserves is capital intensive
and uncertain. The Company may be unable to make the necessary capital
investment to maintain or expand its oil and gas reserves if cash flow from
operations is reduced and external sources of capital become limited or
unavailable. The Company cannot assure you that its future exploration,
development and acquisition activities will result in additional proved reserves
or that it will be able to drill productive wells at acceptable costs.
THE COMPANY'S OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND GAS DRILLING
AND PRODUCTION ACTIVITIES. Oil and gas drilling and production activities are
subject to numerous risks, including the risk that no commercially productive
oil or natural gas reservoirs will be found. The cost of drilling and completing
wells is often uncertain. Oil and gas drilling and production activities may be
shortened, delayed or canceled as a result of a variety of factors, many of
which are beyond the Company's control. These factors include:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o weather conditions; and
o shortages in experienced labor or shortages or delays in the
delivery of equipment.
The prevailing price of oil also affects the cost of and the demand for drilling
rigs, production equipment and related services. The Company cannot assure you
that the new wells it drills will be productive or that it will recover all or
any portion of its investment. Drilling for oil and natural gas may be
unprofitable. Drilling activities can result in dry wells and wells that are
productive but do not produce sufficient net revenues after operating and other
costs.
THE OIL AND GAS INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS. The oil and gas
industry experiences numerous operating risks. These operating risks include the
risk of fire, explosions, blow-outs, pump and pipe failures, abnormally
pressured formations and environmental hazards. Environmental hazards include
oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. If any of
these industry operating risks occur, the Company could have substantial losses.
Substantial losses may be caused by injury or loss of life, severe damage to or
destruction of property, natural resources and equipment, pollution or other
environmental damage, clean-up responsibilities, regulatory investigation and
penalties and suspension of operations. In accordance with industry practice,
the Company maintains insurance against some, but not all, of the risks
described above. The Company cannot assure you that its insurance will be
adequate to cover losses or liabilities. Also, the Company cannot predict the
continued availability of insurance at premium levels that justify its purchase.
THE COMPANY'S CONCENTRATION OF ASSETS INCREASES ITS EXPOSURE TO PRODUCTION
DECLINES. During 1999, the production from the South Monagas Unit in Venezuela
represented approximately 87% of the Company's total daily production. The
Company's production, revenue and cash flow will be adversely affected if
production from the South Monagas Unit decreases significantly.
THE COMPANY'S INTERNATIONAL OPERATIONS MAY BE ADVERSELY AFFECTED BY CURRENCY
FLUCTUATIONS AND ECONOMIC AND POLITICAL DEVELOPMENTS. The Company has
substantially all of its operations in Venezuela and Russia. The expenses of
such operations are payable in local currency while most of the revenue from oil
sales is paid in U.S. dollars. As a result, the Company's operations are subject
to the risk of fluctuations in the relative value of the Bolivar, Ruble and U.S.
dollar. The Company's foreign operations may also be adversely affected by
political and economic developments, royalty and tax increases and other laws or
policies in these countries, as well as U.S. policies affecting trade, taxation
and investment in other countries.
COMPETITION WITHIN THE INDUSTRY MAY ADVERSELY AFFECT THE COMPANY'S OPERATIONS.
The Company operates in a highly competitive environment. The Company competes
with major and independent oil and gas companies for the acquisition of
desirable oil and gas properties and the equipment and labor required to develop
and operate such properties. Many of these competitors have financial and other
resources substantially greater than those of the Company.
THE COMPANY'S OIL AND GAS OPERATIONS ARE SUBJECT TO VARIOUS GOVERNMENTAL
REGULATIONS THAT MATERIALLY AFFECT ITS OPERATIONS. The Company's oil and gas
operations are subject to various foreign governmental regulations. These
regulations may be changed in response to economic or political conditions.
Matters regulated
<PAGE> 33
33
include permits for discharges of wastewaters and other substances generated in
connection with drilling operations, bonds or other financial responsibility
requirements to cover drilling contingencies and well plugging and abandonment
costs, reports concerning operations, the spacing of wells, and unitization and
pooling of properties and taxation. At various times, regulatory agencies have
imposed price controls and limitations on oil and gas production. In order to
conserve supplies of oil and gas, these agencies have restricted the rates of
flow of oil and gas wells below actual production capacity. In addition, the
Company's operations are subject to taxation policies, that in Russia have
changed significantly. The Company cannot predict the ultimate cost of
compliance with these requirements or their effect on its operations.
FOREIGN OPERATIONS RISK. The Company's operations in areas outside the U.S. are
subject to various risks inherent in foreign operations. These risks may
include, among other things, loss of revenue, property and equipment as a result
of hazards such as expropriation, war, insurrection and other political risks,
increases in taxes and governmental royalties, renegotiation of contracts with
governmental entities, changes in laws and policies governing operations of
foreign-based companies, currency restrictions and exchange rate fluctuations
and other uncertainties arising out of foreign government sovereignty over the
Company's international operations. The Company's international operations may
also be adversely affected by laws and policies of the United States affecting
foreign trade and taxation. To date, the Company's international operations have
not been materially affected by these risks.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from adverse changes in oil and gas
prices, interest rates and foreign exchange, as discussed below.
OIL AND GAS PRICES
As an independent oil and gas producer, the Company's revenue, other income and
equity earnings and profitability, reserve values, access to capital and future
rate of growth are substantially dependent upon the prevailing prices of crude
oil and condensate. The Company currently neither produces nor records reserves
related to natural gas. Prevailing prices for such commodities are subject to
wide fluctuation in response to relatively minor changes in supply and demand
and a variety of additional factors beyond the control of the Company.
Historically, prices received for oil and gas production have been volatile and
unpredictable, and such volatility is expected to continue. This volatility is
demonstrated by the average realizations in Venezuela, which declined from
$10.01 in 1997 to $6.75 in 1998 and increased to $9.21 in 1999. From time to
time, the Company has utilized hedging transactions with respect to a portion of
its oil and gas production to achieve a more predictable cash flow, as well as
to reduce its exposure to price fluctuations, but the Company has utilized no
such transactions since 1996. While hedging limits the downside risk of adverse
price movements, it may also limit future revenues from favorable price
movements. Because gains or losses associated with hedging transactions are
included in oil sales when the hedged production is delivered, such gains and
losses are generally offset by similar changes in the realized prices of the
commodities. The Company did not enter into any commodity hedging agreements
during 1998 and 1999.
INTEREST RATES
Total long term debt of $264.6 million at December 31, 1999, included $230
million of fixed-rate senior unsecured notes maturing in 2003 ($125 million) and
2007 ($105 million). Another $34.6 million of debt is attributable to a
floating-rate back-to-back loan facility wherein Benton-Vinccler pays
floating-rate interest to a bank, which then pays to the Company interest on
cash collateral deposited by the Company to support the loans, such interest to
the Company being equal to the floating rate payment less approximately 0.375%
thereby mitigating the floating-rate interest rate risk of such debt. A
hypothetical 10% adverse change in the floating rate would not have had a
material affect on the Company's results of operations for the fiscal year ended
December 31, 1999.
FOREIGN EXCHANGE
The Company's operations are located primarily outside of the United States. In
particular, the Company's current oil producing operations are located in
Venezuela and Russia, countries which have had recent histories of significant
inflation and devaluation. For the Venezuelan operations, oil sales are received
under a contract in effect through 2012 in US dollars; expenditures are both in
US dollars and local currency. For the Russian operations, a majority of the oil
sales are received in US dollars; expenditures are both in US dollars and local
currency, although a larger percentage of the expenditures were in local
currency. The Company has utilized no currency hedging programs to mitigate any
risks associated with operations in these countries, and therefore the Company's
financial results are subject to favorable or unfavorable fluctuations in
exchange rates and inflation in these countries.
<PAGE> 34
34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The information required by this item is included herein on pages S-1 through
S-32.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported under this item.
<PAGE> 35
35
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 2000 Annual Meeting of Stockholders.
<PAGE> 36
36
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Index to Financial Statements: Page
----
Reports of Independent Accountants .............................. S-1
Consolidated Balance Sheets at December 31, 1999 and 1998 ....... S-3
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 1998 and 1997 ................................ S-4
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1999, 1998 and 1997 .................... S-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997 ................................ S-6
Notes to Consolidated Financial Statements....................... S-8
2. Consolidated Financial Statement Schedules:
Schedules for which provision is made in Regulation S-X are not
required under the instructions contained therein, are inapplicable, or
the information is included in the footnotes to the financial
statements.
3. Exhibits:
3.1 Certificate of Incorporation of the Company filed September 9,
1988 (Incorporated by reference to Exhibit 3.1 to the
Company's Registration Statement (Registration No. 33-26333).
3.2 Amendment to Certificate of Incorporation of the Company filed
June 7, 1991 (Previously filed as an exhibit to the Company's
S-1 Registration Statement (Registration No. 33-39214)).
3.3 Restated Bylaws of the Company (Incorporated by reference to
Exhibit 3.3 to the Company's Form 10-K for the year ended
December 31, 1996).
4.1 Form of Common Stock Certificate (Previously filed as an
exhibit to the Company's S-1 Registration Statement
(Registration No. 33-26333)).
10.4 Form of Employment Agreements (Exhibit 10.19) (Previously
filed as an exhibit to the Company's S-1 Registration
Statement (Registration No. 33-26333)).
10.7 Benton Oil and Gas Company 1991-1992 Stock Option Plan
(Exhibit 10.14) (Previously filed as an exhibit to the
Company's S-1 Registration Statement (Registration No.
33-43662)).
10.8 Benton Oil and Gas Company Directors' Stock Option Plan
(Exhibit 10.15) (Previously filed as an exhibit to the
Company's S-1 Registration Statement (Registration No.
33-43662)).
10.9 Agreement dated October 16, 1991 among Benton Oil and Gas
Company, Puror State Geological Enterprises for Survey,
Exploration, Production and Refining of Oil and Gas; and Puror
Oil and Gas Production Association (Exhibit 10.14) (Previously
filed as an exhibit to the Company's S-1 Registration
Statement (Registration No. 33-46077)).
<PAGE> 37
37
10.10 Operating Service Agreement between the Company and Lagoven,
S.A., which has been subsequently combined into PDVSA Petroleo
y Gas, S.A., dated July 31, 1992, (portions have been omitted
pursuant to Rule 406 promulgated under the Securities Act of
1933 and filed separately with the Securities and Exchange
Commission--Exhibit 10.25) (Previously filed as an exhibit to
the Company's S-1 Registration Statement (Registration No.
33-52436)).
10.16 Indenture dated May 2, 1996 between Benton Oil and Gas Company
and First Trust of New York, National Association, Trustee
related to $125,000,000, 11 5/8% Senior Notes Due 2003
(Incorporated by reference to Exhibit 4.1 to the Company's S-4
Registration Statement filed June 17, 1996, SEC Registration
No. 333-06125).
10.17 Indenture dated November 1, 1997 between Benton Oil and Gas
Company and First Trust of New York, National Association,
Trustee related to an aggregate of $115,000,000 principal
amount of 9 3/8% Senior Notes due 2007 (Incorporated by
reference to Exhibit 10.1 to the Company's Form 10-Q for the
quarter ended September 30, 1997).
10.18 Separation Agreement dated January 4, 2000 between Benton Oil
and Gas Company and Mr. A.E. Benton.
10.19 Consulting Agreement dated January 4, 2000 between Benton Oil
and Gas Company and Mr. A.E. Benton.
21.1 List of subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Deloitte & Touche LLP.
23.3 Consent of Huddleston & Co., Inc.
27.1 Financial Data Schedule.
- -------------------
(b) Reports on Form 8-K
No Form 8-K was filed during the last quarter of the registrant's
fiscal year.
<PAGE> 38
38
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Stockholders of Benton Oil and Gas Company
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, stockholders' equity and cash flows
present fairly, in all material respects, the financial position of Benton Oil
and Gas Company and its subsidiaries (the "Company") at December 31, 1999 and
1998, and the results of their operations and their cash flows for each of the
two years in the period ended December 31, 1999 in conformity with accounting
principles generally accepted in the United States. 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 of these statements in accordance with auditing standards
generally accepted in the United States, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note 1 to the financial statements, the Company changed its
method of reporting its investment in Geoilbent.
PricewaterhouseCoopers LLP
San Francisco, California
March 29, 2000
S-1
<PAGE> 39
39
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholder
Benton Oil and Gas Company
Carpinteria, California
We have audited the accompanying consolidated statements of operations,
stockholders' equity, and cash flows of Benton Oil and Gas Company and
subsidiaries for the year 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, Benton Oil and Gas Company's results of operations and cash
flows for the year ended December 31, 1997 in conformity with generally accepted
accounting principles.
As discussed in Note 1 to the financial statements, the Company changed its
method of reporting its investment in Goilbent.
Deloitte & Touche LLP
Los Angeles, California
March 24, 1998 (March 29, 2000
as to the third paragraph
of Note 1)
S-2
<PAGE> 40
40
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1999 1998
-------- --------
<S> <C> <C>
ASSETS
------
CURRENT ASSETS:
Cash and cash equivalents $ 21,147 $ 17,198
Restricted cash 12 12
Marketable securities 4,469 41,173
Accounts and notes receivable:
Accrued oil and gas sales 27,339 16,485
Joint interest and other, net 4,993 13,571
Prepaid expenses and other 1,635 3,385
-------- --------
TOTAL CURRENT ASSETS 59,595 91,824
RESTRICTED CASH 46,449 65,670
OTHER ASSETS 10,569 11,788
DEFERRED INCOME TAXES 12,186 2,976
INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES 61,357 45,436
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of
$16,117 and $30,913 excluded from
amortization in 1999 and 1998, respectively) 435,449 415,847
Furniture and fixtures 10,031 9,608
--------- --------
445,480 425,455
Accumulated depletion, impairment and depreciation (359,325) (318,786)
--------- --------
86,155 106,669
--------- --------
$ 276,311 $324,363
========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
----------------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other $ 3,317 $ 6,459
Accrued interest payable 4,686 5,397
Accrued expenses 17,105 17,271
Income taxes payable 2,392 1,756
Current portion of long term debt 2 14
--------- --------
TOTAL CURRENT LIABILITIES 27,502 30,897
LONG TERM DEBT 264,575 280,002
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST 1,412 475
STOCKHOLDERS' EQUITY (DEFICIT)
Preferred stock, par value $0.01 a share;
Authorized 5,000 shares; outstanding, none
Common stock, par value $0.01 a share;
Authorized 80,000 shares at December 31, 1999 and 1998;
issued 29,627 shares at December 31, 1999 and 1998 296 296
Additional paid-in capital 147,078 147,054
Retained deficit (163,853) (131,569)
Treasury stock, at cost, 50 shares (699) (699)
Employee note receivable, net - (2,093)
--------- --------
TOTAL STOCKHOLDERS' EQUITY (DEFICIT) (17,178) 12,989
--------- --------
$ 276,311 $324,363
========= ========
</TABLE>
See accompanying notes to consolidated financial statements.
S-3
<PAGE> 41
41
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
REVENUES, OTHER INCOME AND EQUITY EARNINGS
Oil sales $ 89,060 $ 82,212 $ 154,033
Net gain on exchange rates 1,044 1,767 2,011
Investment earnings and other 8,986 13,982 12,594
Equity in earnings (losses) of affiliated companies 2,869 (5,062) (820)
--------- --------- ---------
101,959 92,899 167,818
--------- --------- ---------
EXPENSES
Operating expenses 39,393 40,066 35,184
Depletion, depreciation and amortization 16,519 33,157 44,513
Write-down of oil and gas properties and impairments 25,891 193,893 --
General and administrative 25,969 21,485 17,676
Taxes other than on income 3,201 3,177 4,724
Interest 29,247 32,007 24,082
--------- --------- ---------
140,220 323,785 126,179
--------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST
(38,261) (230,886) 41,639
INCOME TAX EXPENSE (BENEFIT) (6,914) (24,411) 17,257
--------- --------- ---------
INCOME (LOSS) BEFORE MINORITY INTEREST (31,347) (206,475) 24,382
MINORITY INTEREST 937 (22,895) 6,333
--------- --------- ---------
NET INCOME (LOSS) $ (32,284) $(183,580) $ 18,049
========= ========= =========
NET INCOME (LOSS) PER COMMON SHARE:
Basic $ (1.09) $ (6.21) $ .62
========= ========= =========
Diluted $ (1.09) $ (6.21) $ .59
========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
S-4
<PAGE> 42
42
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)
<TABLE>
<CAPTION>
EMPLOYEE
COMMON ADDITIONAL RETAINED NOTE
SHARES COMMON PAID-IN EARNINGS TREASURY RECEIVABLE,
ISSUED STOCK CAPITAL (DEFICIT) STOCK NET TOTAL
------ ------ --------- --------- -------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE AT JANUARY 1, 1997 28,898 $289 $140,648 $ 33,962 -- -- $ 174,899
Issuance of common shares:
Exercise of warrants 343 3 3,524 -- -- -- 3,527
Exercise of stock options 281 3 1,953 -- -- -- 1,956
Treasury stock (50 shares) -- -- -- -- $(699) -- (699)
Net income -- -- -- 18,049 -- -- 18,049
------ ---- -------- --------- ----- ------- ---------
BALANCE AT DECEMBER 31, 1997 29,522 295 146,125 52,011 (699) -- 197,732
Issuance of common shares:
Exercise of stock options 105 1 794 -- -- -- 795
Extension of warrants -- -- 135 -- -- -- 135
Employee note receivable, net -- -- -- -- -- $(2,093) (2,093)
Net loss -- -- -- (183,580) -- -- (183,580)
------ ---- -------- --------- ----- ------- ---------
BALANCE AT DECEMBER 31, 1998 29,627 296 147,054 (131,569) (699) (2,093) 12,989
Issuance of Common Shares:
Extension of Warrants -- -- 24 -- -- -- 24
Employee note receivable, net -- -- -- -- -- 2,093 2,093
Net loss -- -- -- (32,284) -- -- (32,284)
------ ---- -------- --------- ----- ------- ---------
BALANCE AT DECEMBER 31, 1999 29,627 $296 $147,078 $(163,853) $(699) $ -- $ (17,178)
====== ==== ======== ========= ===== ======= =========
</TABLE>
See accompanying notes to consolidated financial statements.
S-5
<PAGE> 43
43
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
1999 1998 1997
-------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $(32,284) $(183,580) $ 18,049
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depletion, depreciation and amortization 16,519 33,157 44,513
Write-down and impairment of oil and gas properties 25,891 193,893 --
Amortization of financing costs 1,396 1,442 1,390
Loss on disposition of assets 44 74 11
Equity in (earnings) losses of affiliated companies (2,869) 5,062 820
Allowance and write off of employee notes and accounts receivable 6,231 2,900 --
Minority interest in undistributed earnings (losses) of 937 (22,893) 6,336
subsidiary
Deferred income taxes (9,210) (27,787) 8,132
Changes in operating assets and liabilities:
Accounts and notes receivable (6,414) 18,436 6,007
Prepaid expenses and other 1,750 (1,771) (290)
Accounts payable (3,142) (16,410) 5,356
Accrued interest payable (711) (131) 1,753
Accrued expenses (166) 2,468 (3,960)
Income taxes payable 636 (2,704) 3,849
-------- --------- ---------
NET CASH PROVIDED BY (USED IN) OPERATING
ACTIVITIES (1,392) 2,156 91,966
-------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and equipment 15,100 -- --
Additions of property and equipment (36,984) (101,917) (106,212)
Investment in and advances to affiliated companies (13,052) (17,866) (214)
Increase in restricted cash (214) (230) (13,436)
Decrease in restricted cash 19,435 8,884 11,600
Purchases of marketable securities (29,173) (55,438) (291,943)
Maturities of marketable securities 65,877 170,701 187,511
-------- --------- ---------
NET CASH PROVIDED BY (USED IN) INVESTING
ACTIVITIES 20,989 4,134 (212,694)
-------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from exercise of stock options and warrants 24 930 5,483
Purchase of treasury stock -- -- (699)
Proceeds from issuance of short term borrowings and notes payable -- -- 113,516
Payments on short term borrowings and notes payable (15,439) (12) (10,028)
Increase in other assets (233) (1,741) (7,601)
-------- --------- ---------
NET CASH PROVIDED BY (USED IN) FINANCING
ACTIVITIES (15,648) (823) 100,671
-------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS 3,949 5,467 (20,057)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 17,198 11,731 31,788
-------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 21,147 $ 17,198 $ 11,731
======== ========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for interest expense $ 30,346 $ 30,389 $ 20,700
======== ========= =========
Cash paid during the year for income taxes $ 2,600 $ 2,971 $ 4,166
======== ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
S-6
<PAGE> 44
44
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the year ended December 31, 1999, the Company recorded an allowance for
doubtful accounts related to amounts owed to the Company by its former Chief
Executive Officer, including the portion of the note secured by the Company's
stock and stock options of $2.1 million (see Note 15).
During the year ended December 31, 1998, the Company reduced stockholders'
equity by $2.1 million, the portion of the note receivable from its former Chief
Executive Officer secured by the Company's stock and stock options (see Note
15).
See accompanying notes to consolidated financial statements.
S-7
<PAGE> 45
45
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Benton Oil and Gas Company (the "Company") engages in the exploration,
development, production and management of oil and gas properties. The Company
conducts its business principally in Venezuela and Russia.
The consolidated financial statements include the accounts of all wholly-owned
and majority-owned subsidiaries. The equity method of accounting is used for
companies and other investments in which the Company has significant influence.
All intercompany profits, transactions and balances have been eliminated. The
Company accounts for its investment in Geoilbent, Ltd. ("Geoilbent") and Arctic
Gas Company ("Arctic Gas"), formerly Severneftegaz, based on a fiscal year
ending September 30 (see Note 2).
In January 2000, in connection with the release of Emerging Issues Task Force
(EITF) Issues Summary 00-01, "Applicability of the Pro Rata Method of
Consolidation to Investments in Certain Partnerships and Other Unincorporated
Joint Ventures", the Company reviewed the accounting for its investment in
Geoilbent under the proportionate consolidation method. As a result of this
review, the Company decided to report its investment in Geoilbent using the
equity method for the years ended December 31, 1999, 1998 and 1997. This change
had no effect on net income or the Company's proportionate share of oil and gas
reserves. It did, however, result in the reduction of Company's reported
consolidated net cash flows for the years ended December 31, 1999 and 1998 of
$5.3 million and $0.7 million, respectively, and in the increase in consolidated
net cash flows in 1997 of $0.4 million. For each of the years ended December 31,
1999, 1998 and 1997, revenues, other income and equity earnings were reduced by
the Company's proportionate share, which was $10.3 million, $19.2 million and
$11.2 million, respectively, and expenses were reduced $10.0 million, $19.1
million and $10.9 million, respectively. Summarized financial information for
Geoilbent is included in Note 9.
As a result of the decline in oil prices, the Company instituted in 1998, and
continued in 1999, a capital expenditure program to reduce expenditures to those
that the Company believed were necessary to maintain current producing
properties. In the second half of 1999, oil prices recovered substantially, and
the Company concluded a project to assess its strategic alternatives. In
December 1999, the Company entered into incentive-based development alliance
agreements with Schlumberger and Helmerich & Payne as part of its plans to
resume development of the South Monagas Unit in Venezuela (see Note 10).
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuation in response to change in supply, market uncertainty and a variety of
factors beyond the Company's control.
The Company believes its current cash and cash to be provided by operating
activities will be sufficient to meet the Company's liquidity needs for routine
operations and to service its outstanding debt through 2000. However, if the
Company's future cash requirements are greater than its financial resources, the
Company intends to pursue one or more of the following alternatives: reduce its
capital, operating and administrative expenditures, form strategic joint
ventures or alliances with other industry partners, sell property interests,
merge or combine with another entity, or issue debt or equity securities. There
can be no assurance that any of the alternatives will be available on terms
acceptable to the Company.
REVENUE RECOGNITION
Oil and gas revenue is recognized when title passes to the customer.
CASH AND CASH EQUIVALENTS
Cash equivalents include money market funds and short term certificates of
deposit with original maturity dates of less than three months.
RESTRICTED CASH
Restricted cash represents cash and cash equivalents used as collateral for
financing and letter of credit agreements and is classified as current or
non-current based on the terms of the agreements.
S-8
<PAGE> 46
46
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, consisted of $4.5 million and $41.2 million in
commercial paper at December 31, 1999 and 1998, respectively.
ACCOUNTS AND NOTES RECEIVABLE
Allowance for doubtful accounts related to employee notes at December 31, 1999
and 1998 was $5.9 million and $2.9 million, respectively (see Note 15).
Allowance for doubtful accounts related to joint interest and other
accounts receivable was $0.3 million at December 31, 1999 and 1998.
OTHER ASSETS
Other assets consist principally of costs associated with the issuance of long
term debt. Debt issuance costs are amortized on a straight-line basis over the
life of the debt.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for oil and gas
properties with costs accumulated in cost centers on a country by country basis.
All costs associated with the acquisition, exploration, and development of oil
and gas reserves are capitalized as incurred, including exploration overhead of
$2.1 million, $2.4 million and $1.9 million for the years ended December 31,
1999, 1998 and 1997, respectively, and capitalized interest of $2.1 million for
the year ended December 31, 1999. Only overhead that is directly identified with
acquisition, exploration or development activities is capitalized. All costs
related to production, general corporate overhead and similar activities are
expensed as incurred.
The costs of unproved properties are excluded from amortization until the
properties are evaluated. The Company regularly evaluates its unproved
properties on a country by country basis for possible impairment. If the Company
abandons all exploration efforts in a country where no proved reserves are
assigned, all exploration and acquisition costs associated with the country are
expensed. During 1999 and 1998, the Company recognized $25.9 million and $6.1
million, respectively, of impairment expense associated with certain exploration
activities. Due to the unpredictable nature of exploration drilling activities,
the amount and timing of impairment expenses are difficult to predict with any
certainty. The principal portion of excluded costs, except those related to the
acquisition of Benton Offshore China Company, is expected to be included in
amortizable costs during the next two to three years. The ultimate timing of
when the costs related to the acquisition of Benton Offshore China Company will
be included in amortizable costs is uncertain.
Excluded costs at December 31, 1999 consisted of the following by year incurred
(in thousands):
<TABLE>
<CAPTION>
TOTAL 1999 1998 1997 PRIOR TO 1997
------- ------ ------ ------- --------------
<S> <C> <C> <C> <C> <C>
Property acquisition costs $15,106 $-- $ -- $ -- $15,106
Exploration costs 1,011 47 90 838 36
------- --- ---- ------- -------
$16,117 $47 $ 90 $ 838 $15,142
======= === ==== ======= =======
</TABLE>
All capitalized costs and estimated future development costs (including
estimated dismantlement, restoration and abandonment costs) of proved reserves
are depleted using the units of production method based on the total proved
reserves of the country cost center. Depletion expense, which was all
attributable to the Venezuelan cost center for the years ended December 31,
1999, 1998 and 1997 was $14.8 million, $31.8 million and $43.6 million ($1.53,
$2.62 and $2.83 per equivalent barrel), respectively.
S-9
<PAGE> 47
47
A gain or loss is recognized on the sale of oil and gas properties only when the
sale involves a significant change in the relationship between costs and the
value of proved reserves or the underlying value of unproved property.
Depreciation of furniture and fixtures is computed using the straight-line
method with depreciation rates based upon the estimated useful life of the
property, generally 5 years. Leasehold improvements are depreciated over the
life of the applicable lease. Depreciation expense was $1.6 million, $1.3
million and $0.9 million for the years ended December 31, 1999, 1998 and 1997,
respectively.
The major components of property and equipment at December 31 are as follows (in
thousands):
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Proved property costs $ 409,526 $ 377,720
Costs excluded from amortization 16,117 30,913
Oilfield inventories 9,806 7,214
Furniture and fixtures 10,031 9,608
--------- ---------
445,480 425,455
Accumulated depletion, impairment and depreciation
(359,325) (318,786)
--------- ---------
$ 86,155 $ 106,669
========= =========
</TABLE>
The Company performs a quarterly cost center ceiling test of its oil and gas
properties under the full cost accounting rules of the Securities and Exchange
Commission. During 1998, due to declines in world crude oil prices, the ceiling
tests resulted in write-downs of oil and gas properties in the Venezuela cost
center of $187.8 million.
TAXES ON INCOME
Deferred income taxes reflect the net tax effects, calculated at currently
enacted rates, of (a) future deductible/taxable amounts attributable to events
that have been recognized on a cumulative basis in the financial statements or
income tax returns and (b) operating loss and tax credit carryforwards. A
valuation allowance for deferred tax assets is recorded when it is more likely
than not that the benefit from the deferred tax asset will not be realized.
FOREIGN CURRENCY
The Company has significant operations outside of the United States, principally
in Venezuela and Russia. Both Venezuela and Russia are considered highly
inflationary economies. As a result, operations in those countries are
remeasured in United States dollars, and all currency gains or losses are
recorded in the statement of income. The Company attempts to manage its
operations in a manner to reduce its exposure to foreign exchange losses.
However, there are many factors which affect foreign exchange rates and
resulting exchange gains and losses, many of which are beyond the influence of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the United States dollar. It is not possible to predict
the extent to which the Company may be affected by future changes in exchange
rates.
FINANCIAL INSTRUMENTS
The Company's financial instruments that are exposed to concentrations of credit
risk consist primarily of its cash equivalents, marketable securities and
accounts receivable. The Company's short term investments are placed with a wide
array of financial institutions with high credit ratings. This diversified
investment policy limits the Company's exposure both to credit risk and to
concentrations of credit risk.
Accounts receivable result from oil and gas exploration and production
activities. A majority of the Company's customers and partners are engaged in
the oil and gas business. PDVSA Petroleo y Gas, S.A. purchased 100% of the
Company's Venezuelan oil production during the years ended December 31, 1999,
1998 and 1997. Although the Company does not currently foresee a credit risk
associated with these receivables, repayment is dependent upon the financial
stability of PDVSA Petroleo y Gas, S.A.
S-10
<PAGE> 48
48
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, 1999 and 1998, was
approximately $151.0 million and $149.9 million, respectively.
TREASURY STOCK
In June 1997, the Board of Directors instituted a treasury stock repurchase
program under which the Company is authorized to purchase up to 1,500,000 shares
of its common stock. The shares will be used for re-issuance in connection with
the Company's employee stock option plan, treasury stock or for other corporate
purposes to be determined in the future. During 1997, the Company repurchased
50,000 shares at an average price of $13.99 per share.
COMPREHENSIVE INCOME
Statement of Financial Accounting Standards No. 130 ("SFAS 130") requires that
all items that are required to be recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements. The Company
did not have any items of other comprehensive income during the three years
ended December 31, 1999 and, in accordance with SFAS 130, has not provided a
separate statement of comprehensive income.
RESTRUCTURING
In an effort to reduce general and administrative expenses, the Company reduced
its administrative and technical staff in Carpinteria by 10 persons in October
1999. In connection with the reduction in staff, the Company recorded
termination benefits expense of $0.8 million that are payable from October 1999
through September 2000. The unpaid portion of these benefits of $0.4 million is
included in Accrued Expenses at December 31, 1999.
MINORITY INTERESTS
The Company records a minority interest attributable to the minority
shareholders of its Venezuela subsidiaries. The minority interests in net income
and losses are generally subtracted or added to arrive at consolidated net
income. However, as of December 31, 1998, losses attributable to the minority
shareholder of Benton-Vinccler, a subsidiary owned 80% by the Company, exceeded
its interest in equity capital creating an equity deficit of $3.5 million.
Accordingly, $3.5 million of income attributable to the minority shareholder of
Benton-Vinccler in 1999 has been included in the consolidated net loss of the
Company, eliminating the minority shareholder's equity deficit.
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 1998 and 1997 have been reclassified to conform to the 1999
financial statement presentation.
S-11
<PAGE> 49
49
NOTE 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES
Investments in Geoilbent and Arctic Gas are accounted for using the equity
method due to the significant influence the Company exercises over their
operations and management. Investments include amounts paid to the investee
companies for shares of stock or joint venture interests and other costs
incurred associated with the acquisition and evaluation of technical data for
the oil and gas fields operated by the investee companies. Other investment
costs are amortized using the units of production method based on total proved
reserves of the investee companies. Equity in earnings of Geoilbent and Arctic
Gas are based on a fiscal year ending September 30. Investment in equity in net
assets of Geoilbent in 1999 includes the Company's capital contribution of $2.0
million in December 1998 which was included in other costs, net of amortization,
in 1998. During 1998, due to declines in world oil prices, the Company recorded
a write-down of $10.1 million related to the Geoilbent investment. No dividends
have been paid to the Company from Geoilbent or Arctic Gas.
Equity in earnings and losses and investments in and advances to companies
accounted for using the equity method are as follows (in thousands):
<TABLE>
<CAPTION>
GEOILBENT, LTD. ARCTIC GAS COMPANY TOTAL
--------------------- ---------------------- --------------------
1999 1998 1999 1998 1999 1998
-------- ------- -------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Investments
In equity in net assets $ 28,056 $26,689 $ (2,419) $ (773) $25,637 $25,916
Other costs, net of amortization (542) 200 17,128 8,060 16,586 8,260
-------- ------- -------- -------- ------- -------
Total investments 27,514 26,889 14,709 7,287 42,223 34,176
Advances -- -- 13,364 8,321 13,364 8,321
Equity in earnings (losses) 6,167 2,939 (397) -- 5,770 2,939
-------- ------- -------- -------- ------- -------
Total $ 33,681 $29,828 $ 27,676 $ 15,608 $61,357 $45,436
======== ======= ======== ======== ======= =======
</TABLE>
NOTE 3 - LONG TERM DEBT
Long term debt consists of the following at December 31 (in thousands):
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Senior unsecured notes with interest at 9.375%
See description below $105,000 $105,000
Senior unsecured notes with interest at 11.625%
See description below 125,000 125,000
Benton-Vinccler credit facility with interest at
LIBOR plus 6.125%. Collateralized by a time deposit of the Company
earning approximately LIBOR plus 5.75%
See description below 34,575 50,000
Other 2 16
-------- --------
264,577 280,016
Less current portion 2 14
-------- --------
$264,575 $280,002
======== ========
</TABLE>
In November 1997, the Company issued $115 million in 9.375% senior unsecured
notes due November 1, 2007, of which the Company subsequently repurchased $10
million at their par value. In May 1996, the Company issued $125 million in
11.625% senior unsecured notes due May 1, 2003. Interest on the notes is due May
1 and November 1 of each year. The indenture agreements provide for certain
limitations on liens, additional indebtedness, certain investments and capital
expenditures, dividends, mergers and sales of assets. At December 31, 1999 the
Company was in compliance with all covenants of the indentures.
S-12
<PAGE> 50
50
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. In August 1999, Benton Vinccler
repaid $15.4 million of the long-term credit facility with proceeds from the
sale of certain equipment located in the South Monagas Unit (see Note 10). The
credit facility is collateralized in full by a time deposit of the Company,
bears interest at LIBOR plus 6.125% and matures in August 2001. The Company
receives interest on its time deposit and a security fee on the outstanding
principal of the loan, for a combined total of approximately LIBOR plus 5.75%.
The loan arrangement contains no restrictive covenants and no financial ratio
covenants.
The principal payment requirements for the long term debt outstanding at
December 31, 1999 are as follows for the years ending December 31 (in
thousands):
2000 $ 2
2001 34,575
2002 -
2003 125,000
2004 -
Subsequent Years 105,000
---------
$ 264,577
=========
NOTE 4 - COMMITMENTS AND CONTINGENCIES
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
Unites States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties and that it paid a
price in excess of the fair value of the property. A trial date has been
scheduled for April 25, 2000 and discovery is complete, unless reopened by the
court. The Company intends to vigorously contest the suit, and in management's
opinion it is too early to assess the probability of an unfavorable outcome.
In the normal course of its business, the Company may periodically become
subject to actions threatened or brought by its investors or partners in
connection with the operation or development of its properties or the sale of
securities. The Company is also subject to ordinary litigation that is
incidental to its business, none of which are expected to have a material
adverse effect on the Company's financial statements.
In May 1996, the Company entered into an agreement with Morgan Guaranty which
provided for an $18 million cash collateralized 5-year letter of credit to
secure the Company's performance of the minimum exploration work program
required in the Delta Centro Block in Venezuela. As a result of expenditures
made related to the exploration work program, the letter of credit has been
reduced to $7.7 million.
The Company has employment contracts with three senior management personnel that
provide for annual base salaries, bonus compensation and various benefits. The
contracts provide for the continuation of salary and benefits for the respective
terms of the agreements in the event of termination of employment without cause.
These agreements expire at various times from December 31, 2000 to January 24,
2003. The Company has also entered into employment agreements with five
individuals, which provide for certain severance payments in the event of a
change of control of the Company and subsequent termination by the employees for
good reason.
The Company has entered into various exploration and development contracts in
various countries which require minimum expenditures, some of which required
that the Company secure its commitments by providing letters of credit (see
Notes 10 and 13). The Company has also entered into equity acquisition
agreements in Russia which call for the Company to provide or arrange for
certain amounts of credit financing in order to remove sale and transfer
restrictions on the equity acquired or to maintain ownership in such equity (see
Note 9).
In 1998, the Company entered into a 15-year lease agreement for office space in
Carpinteria, California. The Company has leased 50,000 square feet for
approximately $74,000 per month with annual rent adjustments based on certain
changes in the Consumer Price Index. The Company has entered into a sublease
agreement for a portion of the office space which is not currently needed for
operations. The Company has also entered into a sublease agreement for the
office space that it previously occupied. Rents for the subleases approximate
the Company's lease costs of these facilities.
S-13
<PAGE> 51
51
The Company's aggregate rental commitments for noncancellable agreements at
December 31, 1999 are as follows (in thousands):
Minimum
Lease Sublease
Commitments Income
----------- --------
2000 $ 1,556 $912
2001 1,454 978
2002 1,341 1,005
2003 1,377 837
2004 1,413 402
Thereafter 9,899 -
------- ------
$17,040 $4,134
======= ======
Rental expense was $2.5 million, $2.0 million and $2.0 million for the years
ended December 31, 1999, 1998 and 1997, respectively. Sublease income was $1.0
million and $0.3 million for the years ended December 31, 1999 and 1998. The
Company had no sublease income for the year ended December 31, 1997.
NOTE 5 - TAXES
TAXES OTHER THAN ON INCOME
Benton-Vinccler pays a municipal tax of approximately 2.75% on operating fee
revenues it receives for production from the South Monagas Unit. The Company has
incurred the following Venezuelan municipal taxes and other taxes (in
thousands):
Year Ended December 31: 1999 1998 1997
------ ------ ------
Venezuelan Municipal Taxes $2,303 $2,109 $3,859
Franchise Taxes 139 151 139
Payroll and Other Taxes 759 917 726
------ ------ ------
$3,201 $3,177 $4,724
====== ====== ======
TAXES ON INCOME
The tax effects of significant items comprising the Company's net deferred
income taxes as of December 31, 1999 and 1998 are as follows (in thousands):
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Deferred tax assets:
Operating loss carryforwards $ 36,242 $ 33,446
Difference in basis of property 13,040 6,357
Other 14,817 9,135
Valuation allowance (51,913) (45,962)
-------- --------
Total 12,186 2,976
-------- --------
Deferred tax liabilities:
Difference in basis of property -- --
Other -- --
-------- --------
Net deferred tax asset $ 12,186 $ 2,976
======== ========
</TABLE>
The valuation allowance increased by $7,309 and $7,232 as a result of the
increase in the U.S. deferred tax assets related to the net operating loss
carryforward and to property, respectively. Management has determined that it is
more likely than not that these U.S. deferred tax assets will not be realized.
The valuation allowance decreased by $8,590 related primarily to reversing a
prior valuation allowance related to certain assets in Venezuela. Management has
determined that is more likely than not that this Venezuelan deferred tax asset
will be realized primarily due to an increase in oil prices.
S-14
<PAGE> 52
52
The components of income before income taxes and minority interest are as
follows (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
-------- --------- --------
<S> <C> <C> <C>
Income (loss) before income taxes
United States $(38,025) $ (54,974) $ (5,713)
Foreign (236) (175,912) 47,352
-------- --------- --------
Total $(38,261) $(230,886) $ 41,639
======== ========= ========
</TABLE>
The provision for income taxes consisted of the following at December 31, (in
thousands):
<TABLE>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Current:
United States $ (1,604) $ 1,970 $ 4,617
Foreign 3,900 1,406 4,508
-------- -------- --------
2,296 3,376 9,125
-------- -------- --------
Deferred:
United States -- 3,573 (3,573)
Foreign (9,210) (31,360) 11,705
-------- -------- --------
(9,210) (27,787) 8,132
-------- -------- --------
$ (6,914) $(24,411) $ 17,257
======== ======== ========
</TABLE>
A comparison of the income tax expense at the federal statutory rate to the
Company's provision for income taxes is as follows (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
-------- --------- -------
<S> <C> <C> <C>
Computed tax expense at the statutory rate $(13,392) $ (80,810) $14,651
State income taxes, net of federal effect 3 - 1,072
Rate differentials for foreign income 2,677 21,800 (314)
Change in valuation allowance 5,951 32,121 (657)
Effect of tax law changes (2,220) - -
All other 67 2,478 2,505
------- --------- -------
Income tax expense (benefit) $(6,914) $ (24,411) $17,257
======== ========= ========
</TABLE>
Rate differentials for foreign income result from tax rates different from the
U.S. tax rate being applied in foreign jurisdictions and from the effect of
foreign currency devaluation in foreign subsidiaries which use the U.S. dollar
as their functional currency. The effect of tax law changes relates to benefits
from the recently ratified Venezuela-United States tax treaty.
At December 31, 1999 the Company had, for federal income tax purposes, operating
loss carryforwards of approximately $100 million, expiring in the years 2003
through 2019. If the carryforwards are ultimately realized, approximately $13
million will be credited to additional paid-in capital for tax benefits
associated with deductions for income tax purposes related to stock options.
The Company does not provide deferred income taxes on undistributed earnings of
international consolidated subsidiaries for possible future remittances as all
such earnings are reinvested as part of the Company's ongoing business.
S-15
<PAGE> 53
53
NOTE 6 - STOCK OPTIONS
The Company adopted its 1988 Stock Option Plan in December 1988 authorizing
options to acquire up to 418,824 shares of common stock. Under the plan,
incentive stock options ("ISOs") were granted to a key employee and other
non-qualified stock options ("NQSOs"), stock or bonus rights were granted to
other key employees, directors, independent contractors and consultants at
prices equal to or below market price, exercisable over various periods. The
remaining options to purchase 80,000 shares of common stock for $4.89 per share
were exercised during 1995. During 1989, the Company adopted its 1989
Nonstatutory Stock Option Plan covering 2,000,000 shares of common stock which
were granted to key employees, directors, independent contractors and
consultants at prices equal to or below market prices, exercisable over various
periods. The plan was amended during 1990 to add 1,960,000 shares of common
stock to the plan.
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 plan vest ratably over a three-year period from their dates of
grant and expire ten years from grant date or one year after retirement, if
earlier. Subsequent to shareholder approval of the 1998 Stock-Based Incentive
Plan discussed below, the Board of Directors of the Company terminated future
grants under the 1991-1992 Stock Option Plan.
The Directors' Stock Option Plan permits the granting of nonqualified stock
options ("Director NQSOs") to purchase up to 400,000 shares of common stock to
nonemployee directors of the Company. Upon election as a director and annually
thereafter, each individual who serves as a nonemployee director automatically
is granted an option to purchase 10,000 shares of common stock at a price not
less than the fair market value of common stock on the date of grant. All
Director NQSOs vest automatically on the date of the grant of the options, and
at December 31, 1999, options to purchase 310,000 shares of common stock were
both outstanding and exercisable.
In June 1998, the shareholders of the Company approved the adoption of the 1998
Stock-Based Incentive Plan. The 1998 Stock-Based Incentive Plan authorizes up to
1,400,000 shares of the Company's common stock for grants of ISOs and
NQSOs, stock appreciation rights, restricted stock awards and bonus stock
awards to employees of the Company or its subsidiaries or associated
companies. The exercise price of stock options granted under the plan must be no
less than the fair market value of the Company's common stock on the date of
grant. The total number of shares for which awards may be made to any one
participant during any calendar year cannot exceed 500,000 shares, as adjusted
for any changes in capitalization, such as stock splits. In the event of a
change in control of the Company, all outstanding options become immediately
exercisable to the extent permitted by the plan. All options granted to date
under the 1998 Stock-Based Incentive Plan vest ratably over a three-year period
from their dates of grant and expire ten years from grant date or one year after
retirement, if earlier.
In November 1999, the Company adopted the 1999 Stock Option Plan. The 1999 Stock
Option Plan permits the granting of stock options to purchase up to 2,500,000
shares of the Company's common stock in the form of ISOs and NQSOs to directors,
employees and consultants 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 plan. All options granted to date to employees
and consultants under the 1999 Stock Option Plan vest 50% after the first year
and 25% after each of the following two years from their dates of grant and
expire ten years from grant date or three months after retirement, if earlier.
All options granted to outside directors under the 1999 Stock Option Plan vest
ratably over a three-year period from their dates of grant and expire ten years
from grant date.
S-16
<PAGE> 54
54
A summary of the status of the Company's stock option plans as of December 31,
1999, 1998 and 1997 and changes during the years ending on those dates is
presented below (shares in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
-------------------- ----------------------- -----------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
PRICE SHARES PRICE SHARES PRICE SHARES
-------- -------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of the $ 11.27 3,712 $ 11.78 3,563 $ 10.78 3,037
year:
Options granted 2.37 2,701 8.62 513 14.32 889
Options exercised -- -- 7.77 (81) 6.61 (224)
Options cancelled 6.10 (113) 13.88 (283) 14.41 (139)
----- ----- -----
Outstanding at end of the year 7.55 6,300 11.27 3,712 11.78 3,563
----- ----- -----
Exercisable at end of the year 11.23 3,251 10.63 2,648 9.43 2,206
===== ===== =====
</TABLE>
Significant option groups outstanding at December 31, 1999 and related weighted
average price and life information follow (shares in thousands):
<TABLE>
<CAPTION>
WEIGHTED-
RANGE OF NUMBER OUTSTANDING WEIGHTED-AVERAGE WEIGHTED- NUMBER AVERAGE
EXERCISE AT REMAINING AVERAGE EXERCISABLE AT EXERCISE
PRICES DECEMBER 31, 1999 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 1999 PRICE
----------- -------------------- ------------------ ---------------- ------------------- ----------
<S> <C> <C> <C> <C> <C>
$2.13-2.75 2,688 9.4 Years $ 2.36 82 $ 2.50
4.89-7.00 789 2.8 Years 5.57 773 5.55
7.25-11.00 1,154 4.6 Years 8.82 948 8.84
11.50-16.50 1,121 7.0 Years 13.60 929 13.73
17.38-24.13 548 7.1 Years 20.79 519 20.92
----- -----
6,300 3,251
===== =====
</TABLE>
The weighted average fair value of the stock options granted from the 1998
Stock-Based Incentive Plan, 1991-1992, 1998 and 1999 Stock Option Plans and the
Directors' Stock Option Plan during 1999, 1998 and 1997 was $1.88, $6.30, $9.83
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>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Expected life 9.3 years 9.1 years 9.0 years
Risk-free interest rate 5.9% 5.5% 6.0%
Volatility 73% 62% 54%
Dividend Yield 0% 0% 0%
</TABLE>
The Company accounts for stock-based compensation in accordance with APB 25 and
related interpretations, under which no compensation cost has been recognized
for stock option awards. Had compensation cost for the plans been determined
consistent with SFAS 123, the Company's pro forma net income and earnings per
share for 1999, 1998 and 1997 would have been as follows (in thousands, except
per share data):
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- -------
<S> <C> <C> <C>
Net income (loss) $(38,441) $(190,581) $13,343
======== ========= =======
Net income (loss) per common share:
Basic $ (1.30) $ (6.45) $ 0.46
======== ========= ======
Diluted $ (1.30) $ (6.45) $ 0.44
======== ========= ======
</TABLE>
S-17
<PAGE> 55
55
In connection with the acquisition of Benton Offshore China Company by the
Company in December 1996, the Company adopted the Benton Offshore China Company
1996 Stock Option Plan. Under the plan, Benton Offshore China Company is
authorized to issue up to 107,571 options to purchase the Company's common stock
for $7.00 per share. The plan was adopted in substitution of Benton Offshore
China Company's stock option plan, and all options to purchase shares of Benton
Offshore China Company common stock were replaced under the plan by options to
purchase shares of the Company's common stock. All options were issued upon the
acquisition of Benton Offshore China Company and vested upon issuance. At
December 31, 1999, options to purchase 74,427 shares of common stock were both
outstanding and exercisable.
In addition to options issued pursuant to the plans, options have been issued to
individuals other than officers, directors or employees of the Company at prices
ranging from $10.88 to $11.88 which vest over three to four years. At December
31, 1999, a total of 208,500 options issued outside the plans were outstanding,
205,166 of which were vested. The Company's expense associated with these
options was not material.
NOTE 7 - STOCK WARRANTS
During the years ended December 31, 1996, 1995, and 1994 the Company issued a
total of 587,783, 125,000 and 450,000 warrants, respectively. Each warrant
entitles the holder to purchase one share of common stock at the exercise price
of the warrant. Substantially all the warrants are immediately exercisable upon
issuance.
In January 1996, 587,783 warrants were issued in connection with an exchange
offer under which the Company acquired the outstanding limited partnership
interests in three limited partnerships sponsored by the Company. During the
years ended December 31, 1997 and 1996, 1,578 and 9,215, respectively, of the
warrants were exercised. In November 1998 and again in November 1999, the
Company extended by one year the expiration date of these warrants, which now
will expire on January 18, 2001. The Company recorded $135,000 and $24,000 of
expense in 1998 and 1999, respectively, as a result of these warrant extensions.
In June 1995, 125,000 warrants were issued in connection with the issuance of
$20 million in senior unsecured notes.
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.
The dates the warrants were issued, the expiration dates, the exercise prices
and the number of warrants issued and outstanding at December 31, 1999 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
September 1994 September 2002 9.00 250 250
December 1994 December 2004 12.00 50 50
June 1995 June 2007 17.09 125 125
January 1996 January 2001 11.00 588 577
----- -----
1,163 1,010
===== =====
</TABLE>
S-18
<PAGE> 56
56
NOTE 8 - OPERATING SEGMENTS
The Company regularly allocates resources to and assesses the performance of its
operations by segments that are organized by unique geographic and operating
characteristics. The segments are organized in order to manage regional
business, currency and tax related risks and opportunities. Revenues, other
income and equity earnings from the Venezuela and Russia operating segments are
derived primarily from the production and sale of oil. Other income from USA and
Other is derived primarily from interest earnings on various investments and
consulting revenues. Operations included under the heading "USA and Other"
include corporate management, exploration activities, cash management and
financing activities performed in the United States and other countries which do
not meet the requirements for separate disclosure. All intersegment revenues,
other income and equity earnings, expenses and receivables are eliminated in
order to reconcile to consolidated totals. Corporate general and administrative
and interest expenses are included in the USA and Other segment and are not
allocated to other operating segments.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999: INTER-
(in thousands) USA SEGMENT
VENEZUELA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
--------- --------- ------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues, other income and equity earnings
Oil Sales $ 89,060 $ -- $ -- $ -- $ 89,060
Net gain on exchange rates 1,033 11 -- -- 1,044
Investment earnings and other 758 9,510 2 (1,284) 8,986
Equity in income (loss) of affiliated companies -- -- 2,869 -- 2,869
Intersegment revenues, other income and equity earnings -- 8,906 -- (8,906) --
--------- --------- --------- --------- ---------
Total revenues, other income and equity earnings 90,851 18,427 2,871 (10,190) 101,959
--------- --------- --------- --------- ---------
Expenses
Operating expenses 38,683 34 676 -- 39,393
Depletion, depreciation and amortization 15,705 801 13 -- 16,519
General and administrative expense 4,482 19,729 1,758 -- 25,969
Taxes other than on income 2,501 714 (14) -- 3,201
Interest expense 6,834 23,697 -- (1,284) 29,247
Intersegment expenses 8,906 -- -- (8,906) --
--------- --------- --------- --------- ---------
Total expenses 77,111 44,975 2,433 (10,190) 114,329
--------- --------- --------- --------- ---------
Income (loss) before income taxes 13,740 (26,548) 438 -- (12,370)
Income tax expense (benefit) (7,554) 442 198 -- (6,914)
--------- --------- --------- --------- ---------
Operating segment income (loss) 21,294 (26,990) 240 -- (5,456)
Write-down of oil and gas properties --
and impairments -- (25,891) -- -- (25,891)
Minority interest (937) -- -- -- (937)
--------- --------- --------- --------- ---------
Net income (loss) $ 20,357 $ (52,881) $ 240 $ -- $ (32,284)
========= ========= ========= ========= =========
Total assets $ 124,942 $ 188,000 $ 61,989 $ (98,620) $ 276,311
========= ========= ========= ========= =========
</TABLE>
S-19
<PAGE> 57
57
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998: INTER-
(in thousands) USA SEGMENT
VENEZUELA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
--------- --------- ------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues, other income and equity earnings
Oil Sales $ 82,215 $ (3) $ -- $ -- $ 82,212
Net gain on exchange rates 1,741 26 -- -- 1,767
Investment earnings and other 806 14,014 67 (905) 13,982
Equity in loss of affiliated companies -- -- (5,062) -- (5,062)
Intersegment revenues, other income and equity earnings -- 8,211 -- (8,211) --
--------- --------- -------- -------- ---------
Total revenues, other income and equity earnings 84,762 22,248 (4,995) (9,116) 92,899
--------- --------- -------- -------- ---------
Expenses
Operating expenses 38,905 (20) 1,181 -- 40,066
Depletion, depreciation and amortization 32,532 625 -- -- 33,157
General and administrative expense 4,505 16,662 318 -- 21,485
Taxes other than on income 2,315 862 -- -- 3,177
Interest expense 7,261 25,651 -- (905) 32,007
Intersegment expenses 8,211 -- -- (8,211) --
--------- --------- -------- -------- ---------
Total expenses 93,729 43,780 1,499 (9,116) 129,892
--------- --------- -------- -------- ---------
Loss before income taxes (8,967) (21,532) (6,494) -- (36,993)
Income tax expense (benefit) (29,955) 5,544 -- -- (24,411)
--------- --------- -------- -------- ---------
Operating segment income (loss) 20,988 (27,076) (6,494) -- (12,582)
Write-down of oil and gas properties --
and impairments (187,811) (6,082) -- -- (193,893)
Minority interest 22,895 -- -- -- 22,895
--------- --------- -------- -------- ---------
Net loss $(143,928) $ (33,158) $ (6,494) $ -- $(183,580)
========= ========= ======== ======== =========
Total assets $ 103,419 $ 239,236 $ 51,047 $(69,339) $ 324,363
========= ========= ======== ======== =========
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997: INTER-
(in thousands) USA SEGMENT
VENEZUELA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
--------- --------- ------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues, other income and equity earnings
Oil sales $ 154,119 $ (86) $ -- $ -- $ 154,033
Net gain on exchange rates 2,010 1 -- -- 2,011
Investment earnings and other 1,666 11,863 -- (935) 12,594
Equity in loss of affiliated companies -- -- (820) -- (820)
Intersegment revenues, other income and equity earnings -- 14,605 -- (14,605) --
--------- -------- -------- -------- ---------
Total revenues, other income and equity earnings 157,795 26,383 (820) (15,540) 167,818
--------- -------- -------- -------- ---------
Expenses
Operating expenses 34,363 22 799 -- 35,184
Depletion, depreciation and amortization 44,107 406 -- -- 44,513
General and administrative expense 4,815 12,264 597 -- 17,676
Taxes other than on income 4,046 678 -- -- 4,724
Interest expense 7,412 17,602 3 (935) 24,082
Intersegment expenses 14,605 -- -- (14,605) --
--------- -------- -------- -------- ---------
Total expenses 109,348 30,972 1,399 (15,540) 126,179
--------- -------- -------- -------- ---------
Income (loss) before income taxes 48,447 (4,589) (2,219) -- 41,639
Income tax expense 16,212 1,045 -- -- 17,257
--------- -------- -------- -------- ---------
Operating segment income (loss) 32,235 (5,634) (2,219) -- 24,382
Minority interest (6,333) -- -- -- (6,333)
--------- -------- -------- -------- ---------
Net income (loss) $ 25,902 $ (5,634) $ (2,219) $ -- $ 18,049
========= ======== ======== ======== =========
</TABLE>
S-20
<PAGE> 58
58
NOTE 9 - RUSSIAN OPERATIONS
GEOILBENT, LTD.
The Company owns 34% of Geoilbent, Ltd., a Russian limited liability company
formed in 1991 to develop, produce and market crude oil from the North
Gubkinskoye Field in the West Siberia region of Russia. The Company's investment
in Geoilbent is accounted for using the equity method. Sales quantities
attributable to Geoilbent for the years ended December 31, 1999, 1998 and 1997
were 4,267,647 Bbls, 2,716,476 Bbls and 2,588,671 Bbls, respectively. Prices for
crude oil for the years ended December 31, 1999, 1998 and 1997 averaged $7.59,
$8.72 and $11.28 per barrel, respectively. Depletion expense attributable to the
Geoilbent for the years ended December 31, 1999, 1998 and 1997 was $2.27, $3.69
and $3.33 per barrel, respectively. Summarized financial information for
Geoilbent follows (in thousands). All amounts represent 100% of Geoilbent.
<TABLE>
<CAPTION>
Year ended September 30: 1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
Revenues and other income
Oil sales $ 32,371 $ 23,703 $ 29,191
Other income 6,527 18,023 1,341
-------- -------- ---------
38,898 41,726 30,532
-------- -------- ---------
Expenses
Operating expenses 4,364 6,863 9,071
Depletion, depreciation and amortization 9,669 10,020 8,633
General and administrative 2,655 3,326 3,492
Taxes other than on income 7,809 6,210 10,196
Interest 3,572 2,648 481
-------- -------- ---------
28,069 29,067 31,873
-------- -------- ---------
Income (loss) before income taxes 10,829 12,659 (1,341)
Income tax expense 1,333 562 648
-------- -------- ---------
Net income (loss) $ 9,496 $ 12,097 $ (1,989)
======== ======== =========
At September 30: 1999 1998 1997
-------- -------- ---------
Current assets $ 25,699 $ 7,876 $ 5,485
Other assets 139,488 129,037 102,233
Current liabilities 10,276 15,772 31,409
Other liabilities 54,254 33,999 1,333
Net equity 100,657 87,142 74,976
</TABLE>
The European Bank for Reconstruction and Development ("EBRD") and International
Moscow Bank ("IMB") together have agreed to lend up to $65 million to Geoilbent,
based on achieving certain reserve and production milestones, under parallel
reserve-based loan agreements. Under these loan agreements, the Company and
other shareholders of Geoilbent have significant management and business support
obligations. Each shareholder is jointly and severally liable to EBRD and IMB
for any losses, damages, liabilities, costs, expenses and other amounts suffered
or sustained arising out of any breach by any shareholder of its support
obligations. The loans bear an average interest rate of LIBOR plus 5.25% payable
on January 27 and July 27 each year. Principal payments will be due in varying
installments on the semiannual interest payment dates beginning January 27, 2001
and ending by July 27, 2004. The loan agreements require that Geoilbent meet
certain financial ratios and covenants, including a minimum current ratio, and
provides for certain limitations on liens, additional indebtedness, certain
investment and capital expenditures, dividends, mergers and sales of assets.
Geoilbent began borrowing under these facilities in October 1997 and has
borrowed a total of $46.1 million through September 30, 1999. During October
1999, Geoilbent borrowed another $2.4 million. The proceeds from the loans are
being used by Geoilbent to develop the North Gubkinskoye and Prisklonovoye
Fields in West Siberia, Russia. Because the Company accounts for
S-21
<PAGE> 59
59
its investment in Geoilbent based on a fiscal year ending September 30, the
borrowings in October 1999 will be reflected in the Company's consolidated
financial statements in the quarter ending March 31, 2000. The principal payment
requirements for the long term debt of Geoilbent at September 30, 1999 are as
follows for the years ending September 30 (in thousands):
2000 $ --
2001 8,052
2002 16,000
2003 11,000
2004 11,000
Subsequent Years --
---------
$ 46,052
=========
During 1996 and 1997, the Company incurred $4.1 million in financing costs
related to the establishment of the EBRD financing, which are recorded in other
assets and are subject to amortization over the life of the facility. In 1998,
under an agreement with EBRD, Geoilbent's board ratified an agreement to
reimburse the Company for $2.6 million of such costs, which are included in
accounts receivable. However, due to Geoilbent's need for oil and gas investment
and the declining prices for crude oil, in the second quarter of 1998 the
Company agreed to defer payment of those reimbursements until the first half of
2000. Additionally, during 1998 a subsidiary of the Company recorded an account
receivable-affiliate for pipe it purchased for $5.0 million and sold at cost to
Geoilbent for use in the development of the field. The receivable was repaid
during 1999.
In October 1995, Geoilbent entered into an agreement with Morgan Guaranty for a
credit facility under which the Company provides cash collateral for the loans
to Geoilbent. The credit facility is renewable annually. Loans outstanding under
the credit facility bear interest at either LIBOR plus 0.75%, subject to certain
adjustments, or the Morgan Guaranty prime rate plus 2%, whichever is selected at
the time a loan is made. In conjunction with Geoilbent's reserve-based loan
agreements with the EBRD and IMB, repayment of the credit facility was
subordinated to payments due to the EBRD and IMB and, accordingly, the credit
facility was reclassified from current to long term in 1998. The credit facility
contains no restrictive covenants and no financial ratio covenants. At September
30, 1999, $3.0 million was outstanding under the credit facility.
Excise, pipeline and other taxes, including an oil export tariff of 15 Euros per
ton ($1.97 per Bbl) introduced in 1999, continue to be levied on all oil
producers and certain exporters. Although the Russian regulatory environment has
become less volatile, the Company is unable to predict the impact of taxes,
duties and other burdens for the future.
ARCTIC GAS COMPANY
In April 1998, the Company signed an agreement to earn a 40% equity interest in
Arctic Gas Company, formerly Severneftegaz, in 1998. Arctic Gas owns the
exclusive rights to evaluate, develop and produce the natural gas, condensate,
and oil reserves in the Samburg and Yevo-Yakha license blocks in West Siberia.
The two blocks comprise 837,000 acres within and adjacent to the Urengoy Field,
Russia's largest producing natural gas field. Pursuant to a Cooperation
Agreement between the Company and Arctic Gas, the Company will earn a 40% equity
interest in exchange for providing the initial capital needed to achieve natural
gas production. The Company's capital commitment will be in the form of
providing or arranging a $100 million credit facility for the project, the terms
and timing of which have yet to be finalized. The Company has received voting
shares representing a 40% ownership in Arctic Gas that contain restrictions on
their sale and transfer. A Share Disposition Agreement provides for removal of
the restrictions as disbursements are made under the credit facility. As of
December 31, 1999, the Company had loaned $12.6 million to Arctic Gas pursuant
to an interim credit facility, with interest at LIBOR plus 3%, and had earned
the right to remove restrictions from shares representing an approximate 5%
equity interest. In December 1998 and in 1999, the Company purchased shares
representing an additional 19% equity interest not subject to any sale or
transfer restrictions. The Company owned a total of 59% voting shares of Arctic
Gas as of December 31, 1999, of which 24% was not subject to any restrictions.
At December 31, 1998, the Company owned a total of 50% voting shares of Arctic
Gas, of which 10% was not subject to any restrictions.
Due to the significant influence it exercises over the operating and financial
policies of Arctic Gas, the Company has accounted for its interest in Arctic Gas
using the equity method. The Company's share in the equity losses of Arctic Gas
were $0.4 million for the year ended December 31, 1999, but were not material
for the year ended December 31, 1998. The Company had a weighted average 12%
equity interest not subject to any sale or transfer restrictions for the year
ended December 31, 1999. Certain provisions of Russian corporate law would
effectively require minority shareholder consent in the making of new agreements
between the Company and Arctic Gas, or to the changing of any terms in any
existing agreements between the two partners such as the Cooperation Agreement
and the Share Disposition Agreement, including the conditions upon which the
restrictions on the shares could be removed.
S-22
<PAGE> 60
60
Summarized financial information for Arctic Gas Company follows (in thousands).
All amounts represent 100% of Arctic Gas Company.
<TABLE>
<CAPTION>
<S> <C>
Year ended September 30: 1999
------
Other income $ 585
--------
Expenses
Depreciation 85
General and administrative 2,941
Taxes other than on income 64
Interest 868
--------
3,958
--------
Loss before income taxes (3,373)
Income tax expense --
--------
Net loss $ (3,373)
========
At September 30: 1999
------
Current assets $ 1,513
Other assets 5,043
Current liabilities 18,068
Other liabilities --
Net equity (11,512)
</TABLE>
NOTE 10 - VENEZUELA OPERATIONS
On July 31, 1992, the Company and its partner, Venezolana de Inversiones y
Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement
to reactivate and further develop three Venezuelan oil fields with Lagoven,
S.A., then one of three exploration and production affiliates of the national
oil company, Petroleos de Venezuela, S.A. ("PDVSA") which have subsequently all
been combined into PDVSA Petroleo y Gas, S.A. (all such parent, subsidiary and
affiliated entities hereinafter referred to as "PDVSA"). The operating service
agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South
Monagas Unit (the "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 PDVSA and is responsible for
overall operations of the Unit, including all necessary investments to
reactivate and develop the fields comprising the Unit. Benton-Vinccler receives
an operating fee in U.S. dollars deposited into a U.S. commercial bank account
for each barrel of crude oil produced (subject to periodic adjustments to
reflect changes in a special energy index of the U.S. Consumer Price Index) and
is reimbursed according to a prescribed formula in U.S. dollars for its capital
costs, provided that such operating fee and cost recovery fee cannot exceed the
maximum dollar amount per barrel set forth in the agreement (which amount is
periodically adjusted to reflect changes in the average of certain world crude
oil prices). The Venezuelan government maintains full ownership of all
hydrocarbons in the fields.
In August 1999, Benton-Vinccler sold its recently-constructed power generation
facility located in the Uracoa Field of the South Monagas Unit in Venezuela for
$15.1 million. Concurrently with the sale, Benton-Vinccler entered into a
long-term power purchase agreement with the purchaser of the facility to provide
for the electrical needs of the field throughout the remaining term of the
operating service agreement. The cost of electricity to be provided under terms
of the power purchase agreement approximate that previously paid by
Benton-Vinccler to local utilities. Benton-Vinccler used the proceeds from the
sale to repay indebtedness that is collateralized by a time deposit of the
Company. Permanent repayment of a portion of the loan allowed the Company to
reduce the cash collateral for the loan thereby making such cash available for
working capital needs.
In December 1999, the Company entered into agreements with Schlumberger and
Helmerich & Payne to further develop the South Monagas Unit pursuant to a
long-term incentive-based development program. Schlumberger has agreed to
financial incentives intended to reduce drilling costs, improve initial
production rates of new wells and to increase the average life of the downhole
pumps at South Monagas. As part of Schlumberger's commitment to the program, it
will provide additional technical and engineering resources on-site full-time in
Venezuela and at the Company's offices in Carpinteria, California.
Benton-Vinccler commenced drilling in January 2000 with a one-rig program
initially, and may add a second rig in the middle of 2000.
S-23
<PAGE> 61
61
In January 1996, the Company and its bidding partners, Louisiana Land &
Exploration, which has been subsequently acquired by Burlington Resources, Inc.
("Burlington"), and Norcen Energy Resources, LTD, which has been subsequently
acquired by Union Pacific Resources Group Inc. ("UPR"), were awarded the right
to explore and develop the Delta Centro Block in Venezuela. The contract
requires a minimum exploration work program consisting of completing an 839
kilometer seismic survey and drilling three wells to the depths of 12,000 to
18,000 feet within five years. At the time the block was tendered for
international bidding, PDVSA estimated that this minimum exploration work
program would cost $60 million and required that the Company and the other
partners each post a performance surety bond or standby letter of credit for its
pro rata share of the estimated work commitment expenditures. The Company has a
30% interest in the exploration venture, with Burlington and UPR each owning a
35% interest. Under the terms of the operating agreement, which establishes the
management company of the project, Burlington is the operator of the field and,
therefore, the Company is not able to exercise control of the operations of the
venture. Corporacion Venezolana del Petroleo, S.A., an affiliate of PDVSA, has
the right to obtain a 35% interest in the management company, which dilutes the
voting power of the partners on a pro rata basis. In July 1996, formal
agreements were finalized and executed, and the Company posted an $18 million
standby letter of credit, collateralized in full by a time deposit of the
Company, to secure its 30% share of the minimum exploration work program (see
Note 4). As of December 31, 1998, the Company's share of expenditures to date
was $8.2 million, which was included in the Venezuela cost center after
evaluation for proved reserves, and the standby letter of credit had been
reduced to $11.2 million. During 1999, the Block's first exploration well, the
Jarina 1-X, penetrated a thick potential reservoir sequence, but encountered no
hydrocarbons. The Company continues to evaluate the remaining leads on the
Block, including their potential reserves and risk factors, although the Block's
future commerciality is uncertain. As of December 31, 1999, the Company's share
of expenditures to date was $15.2 million, all of which had been included in the
Venezuela cost center, and the standby letter of credit had been reduced to $7.7
million. While the Venezuela cost center experienced a full cost ceiling test
write-down of $187.8 million in 1998, there were no further impairments in 1999.
NOTE 11 - CHINA OPERATIONS
In December 1996, the Company acquired Benton Offshore China Company, a
privately held corporation headquartered in Denver, Colorado, for 628,142 shares
of common stock and options to purchase 107,571 shares of the Company's common
stock at $7.00 per share, valued in total at $14.6 million. Benton Offshore
China Company's primary asset is a large undeveloped acreage position in the
South China Sea under a petroleum contract with China National Offshore Oil
Corporation ("CNOOC") of the People's Republic of China for an area known as
Wan'An Bei, WAB-21. Benton Offshore China Company will, as a wholly owned
subsidiary of the Company, continue as the operator and contractor of WAB-21.
Benton Offshore China Company has submitted an exploration program and budget to
CNOOC for 1999. However, due to certain territorial disputes over the
sovereignty of the contract area, it is unclear when such program will commence.
In October 1997, the Company signed a farmout agreement with Shell Exploration
(China) Limited ("Shell") whereby the Company acquired a 50% participation
interest in Shell's Liaohe area onshore exploration project in northeast China.
Shell held a petroleum contract with China National Petroleum Corporation
("CNPC") to explore and develop the deep rights in the Qingshui Block, a 563
square kilometer area (approximately 140,000 acres) in the delta of the Liaohe
River. Shell was the operator of the project. In July 1998, the Company paid to
Shell 50% of Shell's prior investment in the Block, which was approximately $4
million ($2 million to the Company). Pursuant to the farmout agreement the
Company was required to pay 100% of the first $8 million of the costs for the
phase one exploration period, after which any development costs were to be
shared equally. During the first six months of 1999, the first exploratory well
on the Qingshui Block was drilled to a total depth of 4,500 meters, and two
reservoirs, the Sha-2 and Sha-3, were tested. Although hydrocarbons were
encountered during drilling of the Qing Deep 22, Benton and operator Shell
concluded in the third quarter that the well was non-commercial. As a result,
the Company elected not to continue to the second exploration phase and has
relinquished its interest in the Block. Accordingly, the Company recognized a
write-down of the capitalized cost related to the farmout agreement of $12.6
million in the third quarter of 1999.
NOTE 12 - SANTA BARBARA OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases ("California Leases") from Molino
Energy Company, LLC ("Molino Energy"), which held 100% of these leases. The
project area covers the Molino, Gaviota and Caliente Fields, located
approximately 35 miles west of Santa Barbara, California. In consideration of
the 40% participation interest in the California Leases, the Company became the
operator of the project and agreed to pay 100% of the first $3.7 million and 53%
of the remainder of the costs of the first well drilled on the block. During
1998, the 2199 #7 exploratory well was drilled to the Gaviota anticline. Drill
stem tests proved to be inconclusive or non-commercial, and the well was
temporarily abandoned for further evaluation. In November 1998, the Company
entered into an agreement to acquire Molino Energy's interest in the California
Leases in exchange for the release of its joint interest billing obligations,
but the transaction has not yet been finalized. In the fourth quarter of 1999,
the Company decided to focus its capital expenditures on existing producing
properties and fulfilling work commitments associated with its other properties.
Because the Company currently has no firm approved plans to continue drilling on
the California Leases and the 2199 #7 exploratory well did not result in
commercial reserves, the Company wrote off all of the capitalized costs
associated with the California Leases of $9.2 million and the joint interest
receivable of $3.1 million due from Molino Energy at December 31, 1999.
S-24
<PAGE> 62
62
NOTE 13 - JORDAN OPERATIONS
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which has been extended to
May 2000, for which it posted a $1 million standby letter of credit,
collateralized in full by a time deposit of the Company. If the Company
ultimately elects to continue through phases two and three, it would be
obligated to spend an additional $18 million over the succeeding six years.
During the first quarter of 1998, the Company reentered two wells and tested two
different reservoirs. The WS-9 well tested significant, but non-commercial
amounts of gas; the WS-10 well resulted in no commercial amounts of
hydrocarbons. Therefore, at December 31, 1998, the Company wrote down $3.7
million in capitalized costs incurred to date related to the PSA. During 1999,
the Company incurred an additional $0.3 million in capitalized costs, which were
written off at December 31, 1999 as a result of the Company's decision to
minimize capital expenditures to those that were necessary in order to maintain
currently producing properties. The Company will continue to reprocess and remap
seismic data and conduct geological studies on the block through May 2000.
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. The
Company's $5.4 million work commitment on the Thies Block, where Petrosen has
recently drilled and completed the Gadiaga #2 discovery well, consisted of
hooking up the existing well, drilling two additional wells and constructing a
41-kilometer (approximately 25-mile) gas pipeline to Senegal's main electric
generating facility near Dakar. In October 1999, the Company entered into an
agreement with First Seismic Corporation ("First Seismic") whereby the Company,
upon receiving a release from Petrosen of its remaining work commitment,
transferred its entire working interests in the Thies Block and paid $0.7
million to First Seismic in exchange for 135,000 series B preferred shares of
First Seismic. The Company performed a valuation of the securities at the date
of the agreement with First Seismic and concluded that the securities had a de
minimis fair value. Accordingly, the Company has not assigned any cost to the
securities. For the year ended December 31, 1999, the Company recorded a
write-down of $1.6 million comprised of $0.9 million of previously capitalized
costs and $0.7 million of payment to First Seismic. At December 31, 1999, the
Company evaluated the securities and believes that the fair value of the
securities has not changed since the date of the agreement.
The Company also obtained exclusive rights from Petrosen to evaluate and
reprocess geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea-Bissau border in the south. The Company has
elected to not continue with the evaluation of, and has relinquished its
interest in, the near-offshore acreage and, accordingly, recognized a write-down
of the capitalized costs related to the acreage of $1.5 million during 1999.
NOTE 15 - RELATED PARTY TRANSACTIONS
In 1996, 1997 and November 1998, the Company made certain unsecured loans to its
then-Chief Executive Officer, A. E. Benton. Each of these loans was evidenced by
a promissory note bearing interest at the rate of 6% per annum. At December 31,
1997 and September 30, 1998, the aggregate outstanding amounts of the loans were
$2.0 million and $4.4 million, respectively. In the fourth quarter of 1998, the
Company loaned Mr. Benton an additional $1.1 million to enable him to pay in
full certain margin account obligations owed to third parties which had obtained
a pledge from Mr. Benton of his shares of Company stock. The Company then
obtained a security interest in those shares of stock, certain personal real
estate and proceeds from certain contractual and stock option agreements. At
December 31, 1998, the $5.5 million owed to the Company by Mr. Benton exceeded
the value of the Company's collateral, due to the decline in the price of the
Company's stock. As a result, the Company recorded an allowance for doubtful
accounts of $2.9 million. The portion of the note secured by the Company's stock
and stock options, $2.1 million, was presented on the Balance Sheet as a
reduction from Stockhoders' Equity at December 31, 1998. In August 1999, Mr.
Benton filed a Chapter 11 (reorganization) bankruptcy petition in the U.S.
Bankruptcy Court for the Central District of California, in Santa Barbara,
California. The Company recorded an additional $2.8 million allowance for
doubtful accounts for the remaining principal and accrued interest owed to the
Company at June 30, 1999, and continues to record additional allowances as
interest accrues ($0.2 million for the period July 1, 1999 to December 31,
1999). Measuring the amount of the allowances requires judgements and estimates,
and the amount eventually realized may differ from the estimate.
S-25
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63
In February 2000, the Company entered into a Separation Agreement and a
Consulting Agreement with Mr. Benton, pursuant to which the Company retained Mr.
Benton as an independent contractor to perform certain services for the Company.
At the same time, Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the full repayment of the Company's loans to
Mr. Benton, including all principal and accrued and accruing interest at the
rate of 6% per annum. Under the proposed plan, which the Company anticipates
will be submitted to the bankruptcy court in the second quarter of 2000, the
Company will retain its security interest in Mr. Benton's 600,000 shares of the
Company's stock and in his stock options, and in a portion of certain proceeds
of his Consulting Agreement. Repayment of the Company's loans to Mr. Benton will
be achieved through Mr. Benton's liquidation of certain real and personal
property assets; a phased liquidation of Company stock resulting from Mr.
Benton's exercise of his Company stock options; and, if necessary, from the
retained interest in the portion of the Consulting Agreement's proceeds. The
amount eventually realized by the Company and the timing of its receipt of
payments will depend upon the timing and results of the liquidation of Mr.
Benton's assets.
Also during 1997 and 1996, the Company made loans to Mr. M.B. Wray, its Vice
Chairman and Mr. J.M. Whipkey, its then-Chief Financial Officer, each loan
bearing interest at 6% and collateralized by a security interest in personal
real estate. On May 11, 1999, Mr. Wray repaid the entire balance of principal
and interest on his loan. At December 31, 1999, the balance owed to the Company
by Mr. Whipkey was $0.4 million, which is due the earlier of December 31, 2000
or the sale of the personal real estate. At December 31, 1998, the balances owed
to the Company by Mr. Wray and Mr. Whipkey were $0.6 million and $0.5 million,
respectively.
In addition, receivables from other employees and directors to the Company
totaled $0.2 million and $0.6 million at December 31, 1999 and December 31,
1998, respectively.
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 were (in thousands, except
per share amounts):
<TABLE>
<CAPTION>
INCOME/
(LOSS) SHARES AMOUNT PER SHARE
--------- -------- -----------------
<S> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999
------------------------------------
BASIC EPS
Loss available to common stockholders $ (32,284) 29,577 $(1.09)
========= ====== ======
Effect of Dilutive Securities:
Stock options and warrants -- --
--------- ------
DILUTED EPS
Loss available to common stockholders $ (32,284) 29,577 $(1.09)
========= ====== ======
FOR THE YEAR ENDED DECEMBER 31, 1998
------------------------------------
BASIC EPS
Loss available to common stockholders $(183,580) 29,554 $(6.21)
========= ====== ======
Effect of Dilutive Securities:
Stock options and warrants -- --
--------- ------
DILUTED EPS
Loss available to common stockholders
and assumed conversions $(183,580) 29,554 $(6.21)
========= ====== ======
FOR THE YEAR ENDED DECEMBER 31, 1997
------------------------------------
BASIC EPS
Income available to common stockholders $ 18,049 29,119 $ 0.62
========= ====== ======
Effect of Dilutive Securities:
Convertible notes and debentures -- --
Stock options and warrants -- 1,715
--------- ------
DILUTED EPS
Income available to common stockholders $ 18,049 30,834 $ 0.59
========= ====== ======
</TABLE>
For the years ended December 31, 1999, 1998 and 1997, 6.2 million, 3.3 million
and 0.6 million options and warrants, respectively, were excluded from the
earnings per share calculations because they were anti-dilutive.
S-26
<PAGE> 64
64
QUARTERLY FINANCIAL DATA (UNAUDITED) (1)
Summarized quarterly financial data is as follows:
<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- --------- ------------ -----------
(amounts in thousands, except per share data)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1999
Revenues, other income and equity earnings $ 19,964 $ 23,636 $ 26,700 $ 31,659
Expenses 27,719 30,586 39,412 42,503
-------- -------- -------- --------
Loss before income taxes and minority interest (7,755) (6,950) (12,712) (10,844)
Income tax expense (benefit) 753 406 1,239 (9,312)
-------- -------- -------- --------
Loss before minority interest (8,508) (7,356) (13,951) (1,532)
Minority interest 155 200 178 404
-------- -------- -------- --------
Net loss $ (8,663) $ (7,556) $(14,129) $ (1,936)
======== ======== ======== ========
Net loss per common share:
Basic $ (0.29) $ (0.26) $ (0.48) $ (0.07)
Diluted $ (0.29) $ (0.26) $ (0.48) $ (0.07)
</TABLE>
<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- --------- ------------ -----------
(amounts in thousands, except per share data)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1998
Revenues, other income and equity earnings $ 30,929 $ 15,388 $ 21,247 $ 25,335
Expenses 53,038 76,678 29,185 164,884
-------- -------- -------- ---------
Loss before income taxes and minority interest (22,109) (61,290) (7,938) (139,549)
Income tax expense (benefit) (744) (7,369) 197 (16,495)
-------- -------- -------- ---------
Loss before minority interest (21,365) (53,921) (8,135) (123,054)
Minority interest (379) (3,878) (296) (18,342)
-------- --------- -------- ---------
Net loss $(20,986) $(50,043) $ (7,839) $(104,712)
======== ======== ======== =========
Net loss per common share:
Basic $ (0.71) $ (1.69) $ (0.27) $ (3.54)
Diluted $ (0.71) $ (1.69) $ (0.27) $ (3.54)
</TABLE>
(1) As discussed in Note 1, the Company changed its method of reporting its
investment in Geoilbent.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
In accordance with Statement of Financial Accounting Standards No. 69,
"Disclosures About Oil and Gas Producing Activities" ("SFAS 69"), this section
provides supplemental information on oil and gas exploration and production
activities of the Company. Tables I through III provide historical cost
information pertaining to costs incurred in exploration, property acquisitions
and development; capitalized costs; and results of operations. Tables IV through
VI present information on the Company's estimated proved reserve quantities,
standardized measure of estimated discounted future net cash flows related to
proved reserves, and changes in estimated discounted future net cash flows.
S-27
<PAGE> 65
65
TABLE I - TOTAL COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES (IN THOUSANDS):
<TABLE>
<CAPTION>
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
------------------------------------------------------ ----------
UNITED STATES
VENEZUELA CHINA AND OTHER SUBTOTAL RUSSIA TOTAL
--------- ----- --------- -------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1999
Development costs $22,361 $ 104 $ 22,465 $ 6,342 $ 28,807
Exploration costs 261 $ 8,480 1,761 10,502 1,345 11,847
------- ------- -------- -------- -------- --------
$22,622 $ 8,480 $ 1,865 $ 32,967 $ 7,687 $ 40,654
======= ======= ======== ======== ======== ========
YEAR ENDED DECEMBER 31, 1998
Development costs $75,928 $ 2,105 $ 78,033 $ 13,276 $ 91,309
Exploration costs 4,230 $ 4,024 7,853 16,107 3,550 19,657
------- ------- -------- -------- -------- --------
$80,158 $ 4,024 $ 9,958 $ 94,140 $ 16,826 $110,966
======= ======= ======== ======== ======== ========
YEAR ENDED DECEMBER 31, 1997
Development costs $95,791 $95,791 $ 2,652 $ 98,443
Exploration costs 3,919 $ 1,088 $ 5,718 10,725 33 10,758
------- ------- -------- -------- -------- --------
$99,710 $ 1,088 $ 5,718 $106,516 $ 2,685 $109,201
======= ======= ======== ======== ======== ========
</TABLE>
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES (IN
THOUSANDS):
<TABLE>
<CAPTION>
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
--------------------------------------------------- ----------
UNITED STATES
VENEZUELA CHINA AND OTHER SUBTOTAL RUSSIA TOTAL
--------- ----- ------------- --------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1999
Proved property costs $ 378,631 $ 12,870 $ 18,025 $ 409,526 $ 68,526 $ 478,052
Costs excluded from amortization -- 16,108 9 16,117 5,004 21,121
Oilfield inventories 9,806 -- -- 9,806 2,084 11,890
Less accumulated depletion and impairment (324,211) (12,870) (17,753) (354,834) (24,102) (378,936)
--------- -------- --------- --------- --------- ---------
$ 64,226 $ 16,108 $ 281 $ 80,615 $ 51,512 $ 132,127
========= ======== ========= ========= ========= =========
DECEMBER 31, 1998
Proved property costs $ 371,369 $ -- $ 6,083 $ 377,452 $ 61,520 $ 438,972
Costs excluded from amortization -- 20,498 10,415 30,913 4,315 35,228
Oilfield inventories 7,214 -- -- 7,214 2,080 9,294
Less accumulated depletion and impairment (309,381) -- (6,083) (315,464) (20,857) (336,321)
--------- -------- --------- --------- --------- ---------
$ 69,202 $ 20,498 $ 10,415 $ 100,115 $ 47,058 $ 147,173
========= ======== ========= ========= ========= =========
DECEMBER 31, 1997
Proved property costs $ 283,469 $ -- $ -- $ 283,469 $ 48,176 $ 331,645
Costs excluded from amortization 7,742 16,473 6,531 30,746 842 31,588
Oilfield inventories 3,627 -- -- 3,627 896 4,523
Less accumulated depletion and impairment (89,727) -- -- (89,727) (8,276) (98,003)
--------- -------- --------- --------- --------- ---------
$ 205,111 $ 16,473 $ 6,531 $ 228,115 $ 41,638 $ 269,753
========= ======== ========= ========= ========= =========
</TABLE>
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<PAGE> 66
66
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (IN
THOUSANDS):
<TABLE>
<CAPTION>
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
--------------------------------------- ------------
UNITED STATES
VENEZUELA AND OTHER SUBTOTAL RUSSIA TOTAL
--------- -------------- -------- ------- ------
<S> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1999
Oil sales $ 89,060 $ -- $ 89,060 $ 11,006 $ 100,066
Expenses:
Operating expenses and taxes other
than on income 38,841 710 39,551 4,139 43,690
Depletion 14,829 -- 14,829 3,325 18,154
Write-down of oil and gas properties and
impairments 25,891 25,891 -- 25,891
Income tax expense 3,812 638 4,450 436 4,886
--------- -------- --------- -------- ---------
Total expenses 57,482 27,239 84,721 7,900 92,621
--------- -------- --------- -------- ---------
Results of operations from oil and gas
producing activities $ 31,578 $(27,239) $ 4,339 $ 3,106 $ 7,445
========= ======== ========= ======== =========
YEAR ENDED DECEMBER 31, 1998
Oil sales $ 82,215 $ (3) $ 82,212 $ 8,059 $ 90,271
Expenses:
Operating expenses and taxes other
than on income 39,069 1,161 40,230 4,445 44,675
Depletion 31,843 -- 31,843 2,474 34,317
Write-down of oil and gas properties and
impairments 187,811 6,082 193,893 10,100 203,993
Income tax benefit (26,793) -- (26,793) -- (26,793)
--------- -------- --------- -------- ---------
Total expenses 231,930 7,243 239,173 17,019 256,192
--------- -------- --------- -------- ---------
Results of operations from oil and gas
producing activities $(149,715) $ (7,246) $(156,961) $ (8,960) $(165,921)
========= ======== ========= ======== =========
YEAR ENDED DECEMBER 31, 1997
Oil sales $ 154,119 $ (86) $ 154,033 $ 9,925 $ 163,958
Expenses:
Operating expenses and taxes other
than on income 34,516 821 35,337 6,551 41,888
Depletion 43,584 -- 43,584 3,079 46,663
Income tax expense 25,656 -- 25,656 -- 25,656
--------- -------- --------- -------- ---------
Total expenses 103,756 821 104,577 9,630 114,207
--------- -------- --------- -------- ---------
Results of operations from oil and gas
producing activities $ 50,363 $ (907) $ 49,456 $ 295 $ 49,751
========= ======== ========= ======== =========
</TABLE>
Geoilbent (34% owned by the Company) and Arctic Gas Company (24% and 10%
ownership not subject to certain sale and transfer restrictions at December 31,
1999 and 1998, respectively), which are accounted for under the equity method,
have been included at their respective ownership interests in the consolidated
financial statements based on a fiscal period ending September 30 and,
accordingly, results of operations for oil and gas producing activities in
Russia reflect the years ended September 30, 1999, 1998 and 1997 for Geoilbent
and the year ended September 30, 1999 for Arctic Gas.
S-29
<PAGE> 67
67
TABLE IV - QUANTITIES OF OIL AND GAS RESERVES
Proved reserves are estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected to
be recovered through existing wells with existing equipment and operating
methods. All Venezuelan reserves are attributable to an operating service
agreement between Benton-Vinccler and PDVSA, under which all mineral rights are
owned by the government of Venezuela.
The Securities and Exchange Commission requires the reserve presentation to be
calculated using year-end prices and costs and assuming a continuation of
existing economic conditions. Proved reserves cannot be measured exactly, and
the estimation of reserves involves judgmental determinations. Reserve estimates
must be reviewed and adjusted periodically to reflect additional information
gained from reservoir performance, new geological and geophysical data and
economic changes. The estimates are based on current technology and economic
conditions, and the Company considers such estimates to be reasonable and
consistent with current knowledge of the characteristics and extent of
production. The estimates include only those amounts considered to be Proved
Reserves and do not include additional amounts which may result from new
discoveries in the future, or from application of secondary and tertiary
recovery processes where facilities are not in place.
Proved Developed Reserves are reserves which can be expected to be recovered
through existing wells with existing equipment and operating methods. This
classification includes: a) proved developed producing reserves which are
reserves expected to be recovered through existing completion intervals now open
for production in existing wells; and b) proved developed nonproducing reserves
which are reserves that exist behind the casing of existing wells which are
expected to be produced in the predictable future, where the cost of making such
oil and gas available for production should be relatively small compared to the
cost of a new well.
Any reserves expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing primary recovery methods
are included as Proved Developed Reserves only after testing by a pilot project
or after the operation of an installed program has confirmed through production
response that increased recovery will be achieved.
Proved Undeveloped Reserves are Proved Reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage are limited to those drilling units offsetting productive units, which
are reasonably certain of production when drilled. Estimates of recoverable
reserves for proved undeveloped reserves may be subject to substantial variation
and actual recoveries may vary materially from estimates.
Proved Reserves for other undrilled units are claimed only where it can be
demonstrated with certainty that there is continuity of production from the
existing productive formation. No estimates for Proved Undeveloped Reserves are
attributable to or included in this table for any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated unless proved effective by actual tests in the area and in the same
reservoir.
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 re-inject or flare such associated natural gas
production, and accordingly, no natural gas proved reserves have been recorded.
Under the joint venture agreement, such reserves are owned by the Company in the
same proportion as all other hydrocarbons in the field, and subsequent changes
in conditions could result in the assignment of value to these reserves.
Changes in previous estimates of proved reserves result from new information
obtained from production history and changes in economic factors.
S-30
<PAGE> 68
68
The evaluations of the oil and gas reserves as of December 31, 1999, 1998, 1997
and 1996 were audited by Huddleston & Co., Inc., independent petroleum
engineers.
<TABLE>
<CAPTION>
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
-------------------------------------- ----------
MINORITY
INTEREST IN NET
VENEZUELA VENEZUELA TOTAL RUSSIA TOTAL
--------- ----------- ----- ------ -----
<S> <C> <C> <C> <C> <C>
PROVED RESERVES-CRUDE OIL, CONDENSATE, AND GAS
LIQUIDS(MBBLS)
YEAR ENDED DECEMBER 31, 1999
Proved reserves beginning of the year 137,835 (27,567) 110,268 31,053 141,321
Revisions of previous estimates (7,488) 1,498 (5,990) (531) (6,521)
Extensions, discoveries and improved recovery 14,281 (2,856) 11,425 11,058 22,483
Production (9,667) 1,933 (7,734) (1,451) (9,185)
-------- ------- -------- ------- --------
Proved reserves end of year 134,961 (26,992) 107,969 40,129 148,098
======== ======= ======== ======= ========
YEAR ENDED DECEMBER 31, 1998
Proved reserves beginning of the year 94,671 (18,934) 75,737 26,113 101,850
Revisions of previous estimates 25,119 (5,024) 20,095 (2,283) 17,812
Extensions, discoveries and improved recovery 30,217 (6,043) 24,174 8,147 32,321
Production (12,172) 2,434 (9,738) (924) (10,662)
-------- ------- -------- ------- --------
Proved reserves end of year 137,835 (27,567) 110,268 31,053 141,321
======== ======= ======== ======= ========
YEAR ENDED DECEMBER 31, 1997
Proved reserves beginning of the year 86,076 (17,215) 68,861 23,544 92,405
Revisions of previous estimates 17,043 (3,409) 13,634 3,449 17,083
Extensions, discoveries and improved recovery 6,947 (1,389) 5,558 - 5,558
Production (15,395) 3,079 (12,316) (880) (13,196)
-------- ------- -------- ------- --------
Proved reserves end of year 94,671 (18,934) 75,737 26,113 101,850
======== ======= ======== ======= ========
PROVED DEVELOPED RESERVES AT:
December 31, 1999 67,119 (13,423) 53,695 15,120 68,815
December 31, 1998 75,636 (15,127) 60,509 9,745 70,254
December 31, 1997 68,868 (13,774) 55,094 5,443 60,537
January 1, 1997 47,805 (9,561) 38,244 3,417 41,661
</TABLE>
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO
PROVED OIL AND GAS RESERVE QUANTITIES
The standardized measure of discounted future net cash flows is presented in
accordance with the provisions of SFAS 69. In preparing this data, assumptions
and estimates have been used, and the Company cautions against viewing this
information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for
fixed and determinable escalations provided by contract, to the estimated future
production of year-end proved reserves. Future cash inflows were reduced by
estimated future production and development costs to determine pre-tax cash
inflows. Future income taxes were estimated by applying the year-end statutory
tax rates to the future pre-tax cash inflows, less the tax basis of the
properties involved, and adjusted for permanent differences and tax credits and
allowances. The resultant future net cash inflows are discounted using a ten
percent discount rate.
Geoilbent received a waiver from the export tariff assessed on all oil produced
in and exported from Russia for 1995. In July 1996, such oil export tariffs were
terminated in conjunction with a loan agreement with the International Monetary
Fund, although a new oil export tariff of 15 Euros per ton ($1.97 per Bbl) was
introduced in 1999. Excise, pipeline and other taxes continue to be levied on
all oil producers and certain exporters. Although the Russian regulatory
environment has become less volatile, the Company is unable to predict the
impact of taxes, duties and other burdens for the future.
S-31
<PAGE> 69
69
<TABLE>
<CAPTION>
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
--------------------------------------- -----------
MINORITY
INTEREST
IN
VENEZUELA VENEZUELA NET TOTAL RUSSIA TOTAL
--------- --------- --------- ------ -----
(amounts in thousands)
<S> <C> <C> <C> <C> <C>
DECEMBER 31, 1999
Future cash inflow $ 1,727,228 $(345,446) $ 1,381,782 $ 566,201 $ 1,947,983
Future production costs (543,976) 108,795 (435,181) (150,370) (585,551)
Future development costs (144,639) 28,928 (115,711) (38,210) (153,921)
----------- --------- ----------- --------- -----------
Future net revenue before income taxes 1,038,613 (207,723) 830,890 377,621 1,208,511
10% annual discount for estimated timing of cash flows (386,930) 77,386 (309,544) (154,032) (463,576)
----------- --------- ----------- --------- -----------
Discounted future net cash flows before income taxes 651,683 (130,337) 521,346 223,589 744,935
Future income taxes, discounted at 10% per annum (175,602) 35,121 (140,481) (47,676) (188,157)
----------- --------- ----------- --------- -----------
Standardized measure of discounted future net cash flows $ 476,081 $ (95,216) $ 380,865 $ 175,913 $ 556,778
=========== ========= =========== ========= ===========
DECEMBER 31, 1998
Future cash inflow $ 778,765 $(155,753) $ 623,012 $ 183,524 $ 806,536
Future production costs (527,856) 105,571 (422,285) (70,953) (493,238)
Future development costs (147,806) 29,561 (118,245) (25,048) (143,293)
----------- --------- ----------- --------- -----------
Future net revenue before income taxes 103,103 (20,621) 82,482 87,523 170,005
10% annual discount for estimated timing of cash flows (40,648) 8,130 (32,518) (37,977) (70,495)
----------- --------- ----------- --------- -----------
Discounted future net cash flows before income taxes 62,455 (12,491) 49,964 49,546 99,510
Future income taxes, discounted at 10% per annum -- -- -- (6,298) (6,298)
----------- --------- ----------- --------- -----------
Standardized measure of discounted future net cash flows $ 62,455 $ (12,491) $ 49,964 $ 43,248 $ 93,212
=========== ========= =========== ========= ===========
DECEMBER 31, 1997
Future cash inflow $ 923,421 $(184,684) $ 738,737 $ 274,190 $ 1,012,927
Future production costs (332,647) 66,529 (266,118) (74,326) (340,444)
Future development costs (70,415) 14,083 (56,332) (53,283) (109,615)
----------- --------- ----------- --------- -----------
Future net revenue before income taxes 520,359 (104,072) 416,287 146,581 562,868
10% annual discount for estimated timing of cash flows (156,321) 31,264 (125,057) (68,885) (193,942)
----------- --------- ----------- --------- -----------
Discounted future net cash flows before income taxes 364,038 (72,808) 291,230 77,696 368,926
Future income taxes, discounted at 10% per annum (72,567) 14,513 (58,054) (14,263) (72,317)
----------- --------- ----------- --------- -----------
Standardized measure of discounted future net cash flows $ 291,471 $ (58,295) $ 233,176 $ 63,433 $ 296,609
=========== ========= =========== ========= ===========
</TABLE>
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
<TABLE>
<CAPTION>
CONSOLIDATED COMPANIES EQUITY AFFILIATES
------------------------------------------- ------------------------------------------
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
(Amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
Present Value at January 1 $ 49,964 $ 233,176 $ 258,841 $ 43,248 $ 63,433 $ 73,423
Sales of oil and gas, net of
related costs (40,303) (34,513) (95,682) (3,238) (3,614) (2,576)
Revisions to estimates of
proved reserves
Pricing 552,614 (295,131) (71,542) 120,742 (43,072) (12,930)
Quantities (26,671) 11,809 56,661 (2,858) (3,134) 11,385
Sales of reserves in place
Extensions, discoveries and
improved recovery,
net of future costs 65,184 22,893 20,580 54,326 18,132 --
Accretion of discount 4,996 29,123 35,748 4,955 7,770 9,071
Change in income taxes (140,481) 58,054 40,590 (41,378) 7,965 3,019
Development costs incurred 28,558 37,832 46,818 4,370 8,311 2,685
Changes in timing and other (112,996) (13,279) (58,838) (4,254) (12,543) (20,644)
--------- --------- --------- --------- -------- --------
Present Value at December 31 $ 380,865 $ 49,964 $ 233,176 $ 175,913 $ 43,248 $ 63,433
========= ========= ========= ========= ======== ========
</TABLE>
<TABLE>
<CAPTION>
TOTAL
--------------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Present Value at January 1 $ 93,212 $ 296,609 $ 332,264
Sales of oil and gas, net of
related costs (43,541) (38,127) (98,258)
Revisions to estimates of
proved reserves
Pricing 673,356 (338,203) (84,472)
Quantities (29,529) 8,675 68,046
Sales of reserves in place
Extensions, discoveries and
improved recovery,
net of future costs 119,510 41,025 20,580
Accretion of discount 9,951 36,893 44,819
Change in income taxes (181,859) 66,019 43,609
Development costs incurred 32,928 46,143 49,503
Changes in timing and other (117,250) (25,822) (79,482)
--------- --------- ---------
Present Value at December 31 $ 556,778 $ 93,212 $ 296,609
========= ========= =========
</TABLE>
S-32
<PAGE> 70
70
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of
Carpinteria, State of California, on the 30th day of March, 2000.
BENTON OIL AND GAS COMPANY
--------------------------
(Registrant)
Date: March 30, 2000 By: /s/Michael B. Wray
--------------------------- ------------------------
Michael B. Wray
Acting Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed by the following persons on the 30th day of March,
2000, on behalf of the Registrant in the capacities indicated:
<TABLE>
<CAPTION>
Signature Title
--------- -----
<S> <C>
/s/Michael B. Wray Director, Acting Chief Executive Officer
-------------------------------------
Michael B. Wray
/s/Bruce M. McIntyre Director
-------------------------------------
Bruce M. McIntyre
/s/David H. Pratt Senior Vice President, Chief Financial
------------------------------------- Officer and Treasurer
David H. Pratt
(Principal Financial Officer)
/s/Chris C. Hickok Vice President-Controller
-------------------------------------
Chris C. Hickok
(Principal Accounting Officer)
/s/A.E. Benton Director
-------------------------------------
A.E. Benton
/s/Richard W. Fetzner Director
-------------------------------------
Richard W. Fetzner
/s/Garrett A. Garrettson Director
-------------------------------------
Garrett A. Garrettson
</TABLE>
<PAGE> 71
71
EXHIBITS
<PAGE> 1
Exhibit 10.18
BENTON OIL AND GAS COMPANY
SEPARATION AGREEMENT
WITH
A.E. BENTON
This Agreement is entered into as of January 4, 2000, by and between
BENTON OIL AND GAS COMPANY, a Delaware corporation ("Company") and A.E. BENTON,
an individual residing in California ("Benton").
WHEREAS, on or about June 1, 1998, the Company, as employer, and
Benton, as employee, entered into a written employment agreement (the
"Employment Agreement");
WHEREAS, on or about August 31, 1999, Benton resigned his officer
positions with the Company; and
WHEREAS, since September 1, 1999, Benton has served as chairman of a
standing committee of the Board of Directors of the Company known as the
"Russian Projects Committee"; and
WHEREAS, Benton and the Company have agreed to terminate the Employment
Agreement on the terms and conditions set forth in this Agreement.
Now therefore, in consideration of the foregoing and the mutual
covenants, representations, agreements and promises set forth herein, and
intending to be legally bound, the parties agree as follows:
1. Termination of Employment Agreement. Subject to the terms of this
Agreement and subject to the execution and delivery by the Company and Benton of
the Consulting Agreement (as defined below), the Employment Agreement is hereby
terminated.
2. Resignation. Benton hereby resigns each and every position which he
currently holds with the Company and all of its subsidiaries and affiliates,
except that Benton shall not resign from the Board of Directors of the Company
nor shall Benton resign from the positions he currently holds with Geoilbent,
Ltd. and Arctic Gas, Ltd. The Company shall enter into a Consulting Agreement
with Benton in the form attached hereto as Exhibit B. Benton shall execute any
and all forms or notifications reasonably necessary to implement such
resignations. Benton acknowledges that the Company, through its Board of
Directors, has advised him that it will not nominate Benton for election to the
Board of Directors at the 2000 annual meeting of the Company.
<PAGE> 2
3. Russian Projects Committee. For so long as Benton is a Director of
the Company, it shall establish a standing committee of the Board of Directors
of the Company known as the "Russian Projects Committee." Benton shall be the
Chairman of that committee and the members of the committee shall be Dr. Richard
W. Fetzner, Dr. Garrett A. Garrettson, and Benton. The committee shall be under
the direction of the Board of Directors and shall be responsible for the
oversight of all of the Company's Russian operations.
4. Stock Options. The Company has granted certain stock options to
Benton as set forth on Exhibit A attached hereto (collectively, the "Stock
Options"). To the extent that the Stock Options have not vested, they will
continue to vest for so long as Benton is providing consulting services under
the Consulting Agreement, and for a period of twelve (12) months thereafter. The
Stock Options, to the extent that they vest, shall be exercisable by Benton at
any time or from time to time for a period of ten (10) years from the grant of
each respective Option. The Compensation Committee of the Company shall execute
minutes reflecting such agreement. Notwithstanding any other term or provision
of this Agreement, Benton acknowledges that he has previously pledged to the
Company all of the Stock Options, including all as yet unvested options, as
collateral security for his outstanding indebtedness to the Company. Benton
agrees that he will execute such documents and instruments as the Company
requests to reaffirm and ratify such pledge.
5. Consulting Agreement. Simultaneously with their execution and
delivery of this Agreement, the Company and Benton shall enter into a consulting
agreement in the form attached hereto as Exhibit B (the "Consulting Agreement").
6. Intention to Continue to Pursue Russian Projects. The Company
expresses its present intention to pursue its current Russian projects;
provided, however, that the Company makes no representations to Benton about its
future plans. In particular, the Company may decide, in its sole discretion, to
dispose of, assign, transfer, abandon or otherwise modify or terminate its plans
for its Russian projects.
7. No Disparagement. Benton and the Company agree that neither party
will issue or make any disparaging remarks about the other party in any trade
publication or other news media.
8. Successors and Assigns; Binding Agreement. This Agreement shall be
binding upon and shall inure to the benefit of the parties hereto and their
respective heirs, personal representatives, successors and assigns. Benton
acknowledges that this Agreement is personal to him and may not be assigned by
him.
9. Governing Law. This Agreement shall be governed by and construed in
accordance with the laws of the State of California, without regard to conflict
of law rules thereof.
10. Waiver. The waiver by either party hereto of any right hereunder of
any failure to perform or breach by the other party hereto shall not be deemed a
waiver or any other right hereunder or of any other failure or breach by the
other party hereto, whether of the same or a similar nature or otherwise. No
waiver shall be deemed to have occurred unless set forth in writing executed by
or on behalf of the waiving party. No such written waiver shall be deemed a
-2-
<PAGE> 3
continuing waiver unless specifically stated therein, and each such waiver shall
operate only as to the specific term or condition waived and shall not
constitute a waiver of such term or condition for the future or as to any act
other than that specifically waived.
11. Notices. All notices or communications that are required or
permitted to be given hereunder shall be in writing and shall be deemed to have
been duly given when delivered personally or sent overnight carrier service to
the parties at the following addresses:
The Company: Benton Oil and Gas Company
6267 Carpinteria Avenue
Suite 200
Carpinteria, California 93013
Benton: 285 Toro Canyon Road
Carpinteria, California 93013
or to such other address as may be specified in a written notice delivered
personally or sent by overnight courier given by one party to the other party
hereunder.
12. Severability. If for any reason any term or provision of this
Agreement is held to be invalid or unenforceable, all other valid terms and
provisions hereof shall remain in full force and effect, and all of the terms
and provisions of this Agreement shall be deemed to be severable in nature. If
for any reason any term or provision containing a restriction set forth herein
is held to cover an area or to be for a length of time which is unreasonable, or
in any other way is construed to be too broad or to any extent invalid, such
term or provision shall not be determined to be null, void and of no effect, but
to the extent the same is or would be valid or enforceable under applicable law,
any court of competent jurisdiction shall construe and interpret or reform this
Agreement to provide for a restriction having the maximum enforceable area, time
period and other provisions (not greater than those contained herein) as shall
be valid and enforceable under applicable law.
13. Integration Clause. This Agreement (including the Exhibits attached
to this Agreement) constitutes the entire agreement between the parties to this
Agreement with respect to the subject matter of this Agreement, and there are no
other terms, obligations, covenants, representations, statements or conditions
except as set forth in this Agreement. No change or amendment to this Agreement
will be effective unless it is contained in a writing denominated as an
"Amendment to Separation Agreement" and is signed by both of the parties to this
Agreement. Failure to insist upon strict compliance with any term or provision
of this Agreement will not be deemed to be a waiver of any rights under a
subsequent act or failure to act. The parties to this Agreement acknowledge and
agree that in the event of any subsequent litigation, arbitration proceeding,
controversy or dispute concerning this Agreement, neither of the parties to this
Agreement will be permitted to offer or introduce into evidence any oral
testimony concerning any oral promises or oral agreements between them that
relate to the subject matter of this Agreement that are not included or referred
to in this Agreement and that are not evidenced by a writing entitled "Amendment
to Separation Agreement" which is signed by both of the parties to this
Agreement.
-3-
<PAGE> 4
14. Counterparts. This Agreement may be executed in counterparts, each
of which shall be deemed an original for all purposes but which, together, shall
constitute one and the same instrument.
IN WITNESS WHEREOF, the parties execute this Agreement effective on the
date set forth above.
BENTON OIL AND GAS COMPANY
By: /s/ Michael B. Wray Date: February 18, 2000
--------------------------------------------- -----------------
Michael B. Wray
Office of the Chief Executive
By: /s/ Bruce M. McIntyre Date: February 17, 2000
--------------------------------------------- -----------------
Bruce M. McIntyre
Office of the Chief Executive
/s/ A.E. Benton Date: February 17, 2000
- ------------------------------------------------ -----------------
A.E. BENTON
-4-
<PAGE> 1
Exhibit 10.19
BENTON OIL AND GAS COMPANY
CONSULTING AGREEMENT
WITH
A.E. BENTON
This Consulting Agreement (the "Agreement") is entered into as of January 4,
2000, by and between BENTON OIL AND GAS COMPANY ("Company") and A.E. BENTON
("Benton").
WHEREAS, Benton has previously held the positions of Chairman,
President and Chief Executive Officer of the Company and certain of its
subsidiaries and affiliates;
WHEREAS, pursuant to a Separation Agreement dated as of January 4,
2000, Benton resigned certain positions with the Company and its subsidiaries
and terminated his Employment Agreement, and agreed to enter into this
Agreement; and
WHEREAS, the Company and Benton have agreed to certain compensation
payments to Benton, which are to be paid to Benton during the term of this
Agreement and, with respect to the "incentive bonus" to be paid to Benton at
such time as the incentive bonus is earned, if at all, regardless of whether
Benton is performing services under this Agreement; and
WHEREAS, the Company desires to secure the benefit of Benton's
knowledge, experience and services by retaining Benton and Benton desires to
provide services to the Company and its subsidiaries and affiliates on the terms
and conditions set forth below;
NOW, THEREFORE, in consideration of the foregoing and the mutual
covenants, representations, agreements and promises set forth herein, and
intending to be legally bound, the parties agree as follows:
1. Consulting. During the Term, as defined below, Benton shall make
himself available to perform consulting services with respect to the businesses
conducted by the Company and its subsidiaries and affiliates as such consulting
services may be requested from time to time by the Chief Executive Officer or
the Board of Directors of the Company. On a quarterly basis, the Board of
Directors, in consultation with Benton, shall set forth goals and objectives to
be pursued by Benton on behalf of the Company. Such services provided by Benton
shall primarily be related to the Company's Russian activities, but may include
other projects, at the discretion of the Company. Benton shall accommodate
reasonable requests for consulting services, and shall devote his reasonable
best efforts, skill and attention to the performance of such consulting
services, including travel reasonably required in the performance of such
consulting services. Such consulting services are estimated to require
approximately 120 hours of Benton's time per month, and may include relocation
in Russia. In connection with his services as a consultant to the Company, the
Board will designate Benton "Managing Director of Russian Operations." Such
designation is honorary in nature and is designated for the sole purpose of
assisting Benton in carrying out his duties under this Agreement. Under no
circumstances is this title deemed to
<PAGE> 2
designate Benton as an officer, employee or representative of the Company, other
than as a consultant under this Agreement, and he shall have no authority to
bind or commit the Company in any way.
2. Term. The term of Benton's engagement under this Agreement shall be
for a period of time beginning on January 4, 2000 and ending on the earlier of
either (i) December 31, 2006 or (ii) the date which this Agreement is earlier
terminated pursuant to Section 6 (the "Term"). There shall be no extension of
this Agreement other than by written instrument duly executed and delivered by
the parties hereto pursuant to Section 14.
3. Consulting Fees and Expenses. During the Term, the Company shall pay
or cause to be paid to Benton the following annual amounts in equal monthly
installments (subject to proration for a partial period) on the last day of each
monthly period during the Term to an account designated in writing by Benton as
follows:
January 4, 2000 to June 1, 2001 $485,000 per annum
June 1, 2001 to December 31, 2001 $120,000 per annum
January 1, 2002 to December 31, 2002 $240,000 per annum
January 1, 2003 to December 31, 2003 $170,000 per annum(1)
January 1, 2004 to December 31, 2004 $100,000 per annum(1)
January 1, 2005 to December 31, 2005 $100,000 per annum(1)
January 1, 2006 to December 31, 2006 $ 50,000 per annum(1)
In addition, Benton shall be reimbursed for reasonable, documented,
out-of-pocket expenses incurred in connection with the consulting services
rendered pursuant to this Agreement; provided that such expenses are submitted
for reimbursement within thirty (30) days of the date such expenses are
incurred.
The Company will reimburse Benton for his cost of life, health and
medical coverage on the same basis as it is being provided to employees of the
Company from time to time, but in no event more than $12,000 per annum. The
Company shall provide adequate office space for Benton to perform his duties at
either, in the Company's sole discretion, the Company's offices or off-site. In
addition, the Company shall provide Benton with support staff and supplies and
equipment, which it believes are reasonably necessary for Benton to perform his
duties, which shall include for at least the first 1 1/2 years of the term of
this Agreement, the support staff and supplies and equipment agreed upon by the
Company and Benton and attached hereto as Exhibit A.
4. Incentive Bonus. Benton shall be entitled to additional incentive
bonuses for so long as the licenses for Geoilbent, Ltd. and Arctic Gas are owned
by the Company or its successors or assigns, measured as follows:
- --------
(1) Such payments, including $50,000 of the payments in 2003, shall be
considered to be a draw against any incentive bonus payable pursuant to Section
4 hereof.
-2-
<PAGE> 3
a. An amount attributable to all hydrocarbon production from
Geoilbent, Ltd. equal to 1% of the net cash receipts received
by the Company in the United States (after deduction of all
taxes imposed on such receipts and excluding any repayment by
Geoilbent, Ltd. of indebtedness or advances by the Company)
for so long as Geoilbent, Ltd. is receiving funds from
hydrocarbon production and distributing such funds to the
Company.
b. An amount attributable to all hydrocarbon production from
Arctic Gas equal to 2% of the net cash receipts received by
the Company in the United States (after deduction of all taxes
imposed on such receipts and excluding any repayment by Arctic
Gas of indebtedness or advances by the Company) for so long as
Arctic Gas is receiving funds from hydrocarbon production and
distributing such funds to the Company.
In addition, in the event that the Company sells directly or indirectly
all or any portion of its interest (the "Interest") in Geoilbent, Ltd. or Arctic
Gas, Benton shall be entitled to an incentive bonus measured by the proceeds
actually received by the Company in the United States equal to 1% of its net
after-tax cash receipts resulting from the sale of the Interest of Geoilbent,
Ltd. and 2% of its net after-tax cash receipts resulting from the sale of the
Interest in Arctic Gas, both excluding any repayment of indebtedness or advances
by the Company.
All such bonuses shall be payable to Benton within sixty (60) days
after such funds have been received by the Company in the United States and
shall be subject to normal withholding taxes. In the event that the Company
directs that any payments to it under this section be directed to some other
jurisdiction other than the United States, Benton shall be entitled to his
incentive bonus as if the funds were received in the United States. Benton
agrees that five (5%) percent of any bonuses received hereunder shall be used
solely for the purpose of making payments to the Company on account of the
unsecured portion of Benton's debt to the Company, in such amounts and upon such
terms and conditions as are contained in a Chapter 11 plan of reorganization
that the Company has either proposed or has voted in favor of, and which is the
subject of a final, non-appealable order confirming such plan of reorganization.
This incentive bonus does not require or imply that the Company will continue to
proceed with the development of Geoilbent, Ltd. or Arctic Gas or that it will
fund any of these activities. Such determination will be made by the Company's
Board of Directors.
5. Right of First Refusal. The Company grants to Benton during the Term
of this Agreement and for a period of one (1) year thereafter, a right of first
refusal to purchase any and all interest (the "Interest") which the Company may
sell or dispose of in any manner with respect to Geoilbent, Ltd. or Arctic Gas.
If the Company desires to sell all or any part of its Interest in Geoilbent or
Arctic Gas, the Company shall first provide to Benton a copy of a bona fide
written offer by a third party ("Third Party") to purchase the Interest which
the Company wishes to accept. Benton thereupon shall have the right, but not the
obligation, to purchase all, but not less than all, of such Interest. The terms
of the purchase of such Interest hereunder shall be the terms set forth in the
bona fide offer by the Third Party. Any election to purchase hereunder shall
reflect the terms upon which the purchaser has elected to purchase the Interest.
If Benton wishes to exercise his right to purchase, he must give written notice
of his intent to exercise the right
-3-
<PAGE> 4
within thirty (30) days after receiving the bona fide offer from the Company. If
Benton does not exercise his rights to purchase, the Company may transfer such
Interest to the Third Party pursuant to the terms of the original offer.
If the Company does not sell its Interest so offered within 180 days
(commencing on the date upon which Benton had been given notification of the
Company's desire to sell the Interest), then such Interest previously released
by Benton and still owned by the Company shall again become subject to the terms
and conditions of this Agreement, but only during the term of the Agreement as
determined under Section 2 hereof.
As used in this Agreement, the Company's "sale or disposal" of an
Interest giving rise to Benton's rights under Sections 4 and 5 hereof shall not
include any farmouts or joint ventures as to such Interest nor the creation of
security interests in the Interest in connection with any financing.
6. Termination. Notwithstanding any provision in this Agreement to the
contrary, prior to the expiration of the term:
a. From January 4, 2000 until June 1, 2001, this Agreement may be
terminated as provided in Exhibit B attached hereto and
incorporated herein.
b. From June 1, 2001 until December 31, 2002, this Agreement may
be terminated by the Company for any of the following reasons
upon ten (10) days written notice to Benton:
i) the Company, in its sole discretion, elects not to
fund the further development of Geoilbent and Arctic
Gas;
ii) in the sole judgment of the majority of the Board of
Directors of the Company, Benton is not performing
his services in the manner the majority of the Board
of Directors deems appropriate;
iii) Benton's conviction of, guilty plea concerning, no
contest plea concerning or confession of fraud,
theft, embezzlement, or similar malfeasance or any
crime of moral turpitude;
iv) in the sole judgment of a majority of the Board of
Directors of the Company, the material breach by
Benton of this Agreement; or
In the event that Benton disputes the Company's action in
terminating this Agreement pursuant to this Section
(b)(iii)-(iv), and submits such dispute to arbitration
pursuant to Section 7 of this Agreement, the Company shall
make, on a timely basis, all payments due to Benton hereunder
into a mutually agreed upon escrow account, until a final
arbitration decision and/or award is made.
c. After December 31, 2002, this Agreement may be terminated by
the Company for any reason upon ten (10) days written notice
to Benton.
-4-
<PAGE> 5
d. This Agreement:
(i) may be terminated by the mutual written agreement of
the parties hereto;
(ii) shall be terminated without any additional action in
the event of Benton's death or adjudicated
incompetency; and
(iii) may be terminated by the Company in the event Benton
shall become disabled by illness, injury or other
incapacity as a result of which Benton is unable to
perform services under this Agreement for a period or
periods aggregating ninety (90) days in any twelve
(12) consecutive months.
e. Any termination of this Agreement by the Company or by Benton
shall be communicated by written notice of termination to the
other party hereto in accordance with Section 12 of this
Agreement. For purposes of this Agreement, a "notice of
termination" shall mean a written notice.
f. Upon termination of this Agreement pursuant to paragraph a, b
or c of this Section, Benton or Benton's heirs, as the case
may be, shall be entitled to receive:
(i) any unpaid fees or bonuses earned through the Date of
Termination and with respect to Section 4, as
provided therein; and
(ii) any unpaid expenses incurred prior to the Date of
Termination and submitted for reimbursement in
accordance with Section 3 hereof; and
(iii) except as otherwise specifically set forth herein,
the Company shall have no further obligation to
Benton or Benton's heirs.
7. Arbitration. Any dispute between the parties arising out of this
Agreement, including but not limited to any dispute regarding any aspect of this
Agreement, its formation, validity, interpretation, effect, performance or
breach ("arbitrable dispute") shall be submitted to arbitration in the city of
Santa Barbara, California, before an experienced arbitrator who is either
licensed to practice law in California, or is a retired judge. The parties agree
to make a good faith effort to select a mutually agreeable arbitrator. However,
if the parties are unable to reach agreement on an arbitrator within 30 days,
one will be selected pursuant to the commercial rules of the American
Arbitration Association or any successor rules thereto. The arbitration shall be
conducted in accordance with the commercial rules of the American Arbitration
Association or any successor rules. The arbitrator shall award to the prevailing
party in any such arbitration its costs, expenses, and reasonable attorneys'
fees incurred in connection with the arbitration, in an aggregate amount not to
exceed $10,000. The Company and Benton shall each be responsible for payment of
one-half of the amount of any arbitrator's fee(s) payable prior to the existence
of a prevailing party, such amounts to be repaid to the prevailing party
pursuant to the previous sentence. The arbitrator's decision and/or award will
be final and binding and fully enforceable and subject to an entry of judgment
by any court of competent jurisdiction.
-5-
<PAGE> 6
8. Benton's Independence and Discretion. Nothing herein contained shall
be construed to constitute the parties hereto as partners or as joint venturers,
or either as agent of the other, or as employer and employee. By virtue of the
relationship described herein Benton's relationship to the Company during the
term of this Agreement shall only be that of an independent contractor, and
Benton shall perform all services pursuant to this Agreement as an independent
contractor. Benton shall not provide any services under the business name of the
Company or its subsidiaries or affiliates and shall not present himself as an
employee of the Company or its subsidiaries or affiliates.
9. Successors and Assigns; Binding Agreement. This Agreement shall be
binding upon and shall inure to the benefit of the parties hereto and their
respective heirs, personal representatives, successors and assigns, provided,
however, that the services to be provided by Benton hereunder are personal to
Benton and may not be delegated or assigned by him.
10. Governing Law. This Agreement shall be governed by and construed in
accordance with the laws of the State of California, without regard to conflict
of law rules thereof.
11. Waiver. The waiver by either party hereto of any right hereunder of
any failure to perform or breach by the other party hereto shall not be deemed a
waiver or any other right hereunder or of any other failure or breach by the
other party hereto, whether of the same or a similar nature or otherwise. No
waiver shall be deemed to have occurred unless set forth in writing executed by
or on behalf of the waiving party. No such written waiver shall be deemed a
continuing waiver unless specifically stated therein, and each such waiver shall
operate only as to the specific term or condition waived and shall not
constitute a waiver of such term or condition for the future or as to any act
other than that specifically waived.
12. Notices. All notices or communications that are required or
permitted to be given hereunder shall be in writing and shall be deemed to have
been duly given when delivered personally or sent overnight carrier service to
the parties at the following addresses:
The Company: Benton Oil and Gas Company
6267 Carpinteria Avenue
Suite 200
Carpinteria, California 93013
Benton: XXXXXXXXXXXXXXXXXXXX
XXXXXXXXXXXXXXXXXXXXXXXXXXXXXX
or to such other address as may be specified in a written notice delivered
personally or sent by overnight courier given by one party to the other party
hereunder.
13. Severability. If for any reason any term or provision of this
Agreement is held to be invalid or unenforceable, all other valid terms and
provisions hereof shall remain in full force and effect, and all of the terms
and provisions of this Agreement shall be deemed to be severable in nature.
-6-
<PAGE> 7
14. Integration Clause. This Agreement (including the Exhibit attached
to this Agreement) constitutes the entire agreement between the parties to this
Agreement with respect to the subject matter of this Agreement, and there are no
other terms, obligations, covenants, representations, statements or conditions
except as set forth in this Agreement. No change or amendment to this Agreement
will be effective unless it is contained in a writing denominated as an
"Amendment to Consulting Agreement" and is signed by both of the parties to this
Agreement. Failure to insist upon strict compliance with any term or provision
of this Agreement will not be deemed to be a waiver of any rights under a
subsequent act or failure to act. The parties to this Agreement acknowledge and
agree that in the event of any subsequent litigation, arbitration proceeding,
controversy or dispute concerning this Agreement, neither of the parties to this
Agreement will be permitted to offer or introduce into evidence any oral
testimony concerning any oral promises or oral agreements between them that
relate to the subject matter of this Agreement that are not included or referred
to in this Agreement and that are not evidenced by a writing entitled "Amendment
to Consulting Agreement" which is signed by both of the parties to this
Agreement.
15. Counterparts. This Agreement may be executed in counterparts, each
of which shall be deemed an original for all purposes but which, together, shall
constitute one and the same instrument.
16. Agreement on Plan of Bankruptcy. The parties agree that at the
Company's sole discretion, this Agreement may be declared by the Company to be
null and void if: (1) Benton and the Company have not agreed upon and filed a
proposed joint plan of reorganization and disclosure statement in Benton's
Chapter 11 bankruptcy case by February 15, 2000; and/or (2) at any time prior to
the entry of a final, nonappealable order confirming a plan of reorganization
for Benton in his Chapter 11 bankruptcy case that the Company either voted in
favor of or proposed, Benton does not support the Company's position.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement
effective on the date set forth above.
BENTON OIL AND GAS COMPANY
By: /s/ Michael B. Wray Date: February 18, 2000
--------------------------------------------- -----------------
Michael B. Wray
Office of the Chief Executive
By: /s/ Bruce M. McIntyre Date: February 17, 2000
--------------------------------------------- -----------------
Bruce M. McIntyre
Office of the Chief Executive
/s/ A.E. Benton Date: February 17, 2000
- ------------------------------------------------ -----------------
A.E. BENTON
-7-
<PAGE> 8
EXHIBIT A
TO
CONSULTING AGREEMENT
WITH
A.E. BENTON
1. Fax Machine
2. Computer/Software
3. Copier
4. Telephone
5. Cellular Phone
6. Postage
7. General Office Supplies
8. Office Space/Furniture
9. Office Maintenance
10. Credit Card for Business Use and Telephone Calling Card
11. SOS International Service Card.
<PAGE> 9
EXHIBIT B
1. Termination
1.1. Right to Terminate by Company. Company may terminate Benton's
Consulting Agreement, through its Board of Directors, immediately upon Notice of
Termination for Cause. The term "Cause" when referring to termination by Company
means only the following and any other termination shall be without Cause: (i)
Benton's gross dereliction of his duties; (ii) theft or misappropriation of any
property of Company by Benton; (iii) conviction of Benton of a felony or of any
crime involving dishonesty or moral turpitude; or (iv) violation by Benton of
the provisions of this Agreement; provided that, termination for violation by
Benton of the provisions of this Agreement shall occur only after 30 days'
advance written notice by Company to Benton containing reasonably specific
details of the alleged breach and failure to cure the same within such 30 day
period.
1.2. Results of Termination by Company.
(i) Termination for Cause. On the Date of Termination for
Cause of Benton's employment by Company, Company shall pay the fee due under the
Consulting Agreement then in effect through the Date of Termination.
1.3. Termination for Death or Disability. Benton's agreement shall
terminate upon the earliest of the events specified below:
(i) the death of Benton;
(ii) the Date of Termination specified in a written Notice of
Termination by reason of physical or mental condition of Benton which shall
substantially incapacitate him from performing his principal duties
("Disability") delivered by the Board of Directors to Benton at least 30 days
prior to the specified Date of Termination, which shall be any date after the
expiration of any 120 consecutive days during all of which Benton shall be
unable, by reason of his Disability, to perform his principal duties, provided
however, that such Notice of Termination shall be null and void if Benton fully
resumes the performance of his duties under this Agreement prior to the Date of
Termination set forth in the Notice of Termination.
<PAGE> 10
1.4. Results of Termination for Death or Disability.
(i) Death of Benton. If Benton's agreement is terminated due
to the death of Benton, Company shall pay the Base salary due Benton through the
date on which death occurs;
(ii) Disability of Benton. If Benton's employment is terminated
due to the Disability of Benton as described in Section 1.3 (ii) of this of this
Agreement, Company shall continue to pay Benton his consulting fee for the
90-day period following the specified Date of Termination. After this 90-day
period, Company agrees to pay to Benton during each month for the next six
months an amount equal to the difference between Benton's monthly fee and the
amount which Benton receives or is entitled to receive from any long term
disability insurance coverage provided at the cost of the Company for Benton.
1.5. Right to Terminate by Benton. Benton may terminate his agreement
for good reason or without good reason upon 30 days' written Notice of
Termination. The term "Good Reason" when referring to termination by Benton
means a material breach by Company of its obligations under this Agreement,
including the payment of money, and only after 30 days' advance written notice
of Termination containing reasonably specific details of the alleged breach and
failure to cure the same within such 30 day period. Termination for any other
reason shall be without Good Reason.
1.6. Results of Termination by Benton.
(i) Termination for Good Reason. Upon Benton's termination of
his agreement for Good Reason, Company shall pay the fee then in effect through
June 1, 2001 and Company shall maintain in full force and effect, for the
continued benefit of Benton and Benton's dependents for a period terminating on
June 1, 2001 all life, accidental death, medical insurance plans or programs in
which Benton was entitled to participate immediately prior to the Date of
Termination, provided that Benton's continued participation is possible under
the general terms and provisions of such plans and Benton continues to pay an
amount equal to his regular contribution for such participation, if any.
(ii) Termination Without Good Reason. Upon employee's
termination without Good Reason of his agreement, Company shall pay the fee due
Benton through the Date of Termination.
2. Change in Control
2.1 Change in Control and Proposed Change in Control Defined.
(i) No benefits shall be payable to Benton pursuant to the
this Section 2 unless there shall have been a Change in Control of the Company
as set for the below. For purposes of Company of a nature that This Agreement a
"Change in Control" shall mean a Change in Control of Company of a nature that
would be required to be reported in response to Item 1 (a) of the
2
<PAGE> 11
Current Report on Form 8-K, as in effect on the date hereof, pursuant to Section
13 or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange
Act"); provided that, without limitation, such a Change in Control shall be
deemed to have occurred at such time as
(a) any Person, as such term is used in Section 13 (d) and 14
(d) of the Exchange Act (other than Company, any trustee or other
fiduciary holding securities under an employee benefit plan of Company,
or any company owned, directly or indirectly, by the stockholders of
Company in substantially the same proportions as their ownership of
stock of Company) is or becomes the "beneficial owner" (as defined in
Rule 13d-3 under the Exchange Act), directly or indirectly, of 25% or
more of the combined voting power of Company's outstanding securities;
(b) individuals who constitute the Board on the date hereof
(the "Incumbent Board") cease for any reason to constitute at least a
majority thereof, provided that any person becoming a director
subsequent to the date hereof whose election, or nomination for
election by Company's shareholders, was approved by a vote of at least
a majority of the directors comprising the Incumbent Board (either by a
specific vote or by approval of the proxy statement of Company in which
such person is named as a nominee for director, without objection to
such nomination) shall be, for purposes of this clause (b), considered
as though such person were a member of the Incumbent Board.
(c) the stockholders of Company approve a merger or
consolidation of Company with any other company, other than (1) a
merger or consolidation which would result in the voting securities of
Company outstanding immediately prior thereto continuing to represent
(either by remaining outstanding by or being converted into voting
securities of the surviving entity) more than 50% of the combined
voting power of the voting securities of Company or such surviving
entity outstanding immediately after such merger or consolidation or
(2) a merger or consolidation effected to implement a recapitalization
of Company (or similar transition) in which no "Person" (as defined
above) acquires more than 25% of the combined voting power of the
Company's then outstanding securities; or
(d) the stockholders of Company approve a plan of complete
liquidation of Company or an agreement for the sale or disposition by
Company of all or substantially all of Company's assets.
Notwithstanding anything in the foregoing to the contrary, no Change in
Control shall be deemed to have occurred for purposes of this Agreement by
virtue of any transaction which results in Benton, or a group of Persons which
includes Benton, acquiring, directly or indirectly, 25% or more of the combined
voting power of the Company's outstanding securities.
(ii) For purposes of this Agreement, a "Proposed Change in
Control" of Company shall be deemed to have occurred if:
3
<PAGE> 12
(a) Company enters in an agreement, the consummation of which
would result in the occurrence of a Change in Control of Company;
(b) any person (including Company) publicly announces an
intention to take or to consider taking actions which if consummated
would constitute a change in Control of Company;
(c) any person (other than a trustee or other fiduciary
holding securities under an employee benefit plan of Company, or a
company owned, directly or indirectly, by the stockholders of Company
in substantially the same proportions as their ownership of stock of
Company), who is or becomes the beneficial owner, directly or
indirectly, of securities of the Company representing 9.5% or more of
the combined voting power of Company's then outstanding securities,
increases his beneficial ownership of such securities through either
successive or simultaneous acquisition by a total of 3 percentage
points or more over the percentage so owned by such person prior to
such acquisition; or
(d) the Board adopts a resolution to the effect that, for
purposes of this Agreement, a Proposed Change in Control of Company has
occurred.
2.2 Continuing Consulting Agreement. If a Proposed Change in Control
occurs prior to the expiration of this Agreement, Benton agrees that he will
remain as a consultant of Company until the earliest of (a) a date which in 180
days from the occurrence of such Proposed Change in control of Company, or (b)
the termination of Benton's Consulting Agreement by reason of death or
Disability as defined in Section 1.3 of this Agreement.
If a Proposed Change in Control occurs prior to the expiration
of this Agreement, Company agrees that it will not terminate Benton's Consulting
Agreement without Cause until the earliest of (a) a date on which the Board
adopts a resolution to the effect that the actions leading to such Proposed
Change in control have been abandoned or terminated, or (b) the termination of
Benton's Consulting Agreement by reason of Death or Disability as defined in
Section 1.3 of this Agreement.
2.3 Compensation Upon Termination or During Disability.
(i) Compensation Upon Disability. During any period following
a Change in Control that Benton fails to perform his duties as a result of
Disability, Company shall pay Benton his fee for the 90-day period following the
specified Date of Termination. After this 90-day period, Company agrees to pay
to Benton during each month for the next six months an amount equal to the
difference between Benton's monthly fee and the amount which Benton receives or
is entitled to receive from any long term disability insurance coverage carried
by Benton.
(ii) Compensation Upon Termination by Company for Cause. If
Benton's agreement shall be terminated by Company for Cause following a Change
in Control, Company shall pay the fee then in effect through the Date of
Termination.
4
<PAGE> 13
(iii) Compensation Upon Termination by Benton for Good Reason.
If, after a Change in Control and prior to June 1, 2001, Benton's agreement
shall be terminated by Benton for Good Reason based on an event occurring
concurrent with or subsequent to a Change in Control, then, at the time
specified in Subsection (vii), Benton shall be entitled, without regard to any
contrary provisions, to the benefits as provided below:
(a) The Company shall pay Benton his full fee through the Date
of Termination at the rate in effect just prior to the time a Notice of
Termination is given; and
(b) As severance pay and in lieu of any further payments for
periods subsequent to the Date of Termination, Company shall pay to
Benton at the time specified in subsection (vii), a single lump sum
payment (the "Payment") in an amount in cash equal to three times
Benton's annual fee of $485,000.
(iv) Termination by Benton for Good Reason. Benton may
terminate his engagement for Good Reason upon 90 day's written Notice of
Termination. Termination by Benton for Good Reason shall have the following
additional meanings:
(a) a reduction by Company in Benton's fee as in effect
immediately prior to the Change in Control;
(b) Company's requiring Benton to be based anywhere other than
where Benton's office is located immediately prior to the Change in
Control, or as set forth in his Agreement, except for required travel
on Company's business to an extent substantially consistent with the
business travel obligations which Benton undertook on behalf of the
Company prior to the Change in Control; and
(c) the failure by Company to obtain from any successor the
assent to this Agreement.
5
<PAGE> 1
72
EXHIBIT 21.1
BENTON OIL AND GAS COMPANY
LIST OF SUBSIDIARIES
<TABLE>
<CAPTION>
JURISDICTION
NAME OF INCORPORATION
- ------------------------------------------------------------- -----------------------------------
<S> <C>
Benton-Vinccler, C.A.* Venezuela
Energy International Financial Institution, Ltd.* Cayman Islands
Benton Offshore China Company Colorado
Benton Offshore China Holding Company Delaware
Geoilbent, Ltd.* Russia
Arctic Gas Company Russia
</TABLE>
The names of certain subsidiaries have been omitted in reliance upon Item
601(b)(21)(ii) of Regulation S-K.
*All subsidiaries are wholly-owned by Benton Oil and Gas Company, except
Benton-Vinccler, C.A. and Energy International Financial Institution which are
owned 80% by Benton Oil and Gas Company, Geoilbent, Ltd. which is owned 34% by
Benton Oil and Gas Company and Arctic Gas Company which is owned 24% by Benton
Oil and Gas Company.
<PAGE> 1
73
EXHIBIT 23.1
BENTON OIL AND GAS COMPANY
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-8 (Nos. 33-37124, 333-19679 and 333-94823), Form S-3 (Nos.
33-70146, 33-79494, 333-00135 and 333-17231) and Form S-4 (Nos. 33-61299,
33-42139 and 333-06125) of Benton Oil and Gas Company of our report dated March
30, 2000 relating to the financial statements, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
San Francisco, California
March 30, 2000
<PAGE> 1
74
EXHIBIT 23.2
BENTON OIL AND GAS COMPANY
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-37124, 333-19679 and 333-94823 on Form S-8, 33-70146 on Form S-3, 333-00135
on Form S-3, 333-17231 on Form S-3, 33-79494 on Form S-3, 33-61299 on Form S-4,
33-42139 on Form S-4 and 333-06125 on Form S-4 of Benton Oil and Gas Company of
our report dated March 24, 1998 (March 29, 2000 as to the third paragraph of
Note 1) appearing in this Annual Report on Form 10-K of Benton Oil and Gas
Company for the year ended December 31, 1999.
Deloitte & Touche LLP
Los Angeles, California
March 29, 2000
<PAGE> 1
75
EXHIBIT 23.3
BENTON OIL AND GAS COMPANY
INDEPENDENT PETROLEUM ENGINEERS' CONSENT
Huddleston & Co., Inc., hereby consents to the use of its name in reference to
it regarding its audit of the Benton Oil and Gas Company reserve reports, dated
as of December 31, 1999 in the Form 10-K Annual Report of Benton Oil and Gas
Company to be filed with the Securities and Exchange Commission.
Peter D. Huddleston, P.E.
Huddleston & Co., Inc.
Houston, Texas
March 24, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K
FOR THE PERIOD ENDED DECEMBER 31, 1999 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-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<EXCHANGE-RATE> 1
<CASH> 21,147
<SECURITIES> 4,469
<RECEIVABLES> 27,339
<ALLOWANCES> 6,187
<INVENTORY> 0
<CURRENT-ASSETS> 59,595
<PP&E> 445,480
<DEPRECIATION> 359,325
<TOTAL-ASSETS> 276,311
<CURRENT-LIABILITIES> 27,502
<BONDS> 264,575
0
0
<COMMON> 296
<OTHER-SE> (17,474)
<TOTAL-LIABILITY-AND-EQUITY> 276,311
<SALES> 89,060
<TOTAL-REVENUES> 101,959
<CGS> 55,912
<TOTAL-COSTS> 55,912
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 29,247
<INCOME-PRETAX> (38,262)
<INCOME-TAX> (6,914)
<INCOME-CONTINUING> (31,348)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (32,284)
<EPS-BASIC> (1.09)
<EPS-DILUTED> (1.09)
</TABLE>
