BENTON OIL & GAS CO - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

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
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BENTON OIL AND GAS COMPANY
(Exact name of registrant as specified in its charter)

DELAWARE 77-0196707
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification Number)

15835 PARK TEN PLACE DRIVE, SUITE 115 77084
HOUSTON, TEXAS (Zip Code)
(Address of principal executive offices)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE
(281) 579-6700

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

On March 25, 2002, the aggregate market value of the shares of voting stock
of Registrant held by non-affiliates was approximately $138,096,369 based on a
closing sales price on NYSE of $4.03.

As of March 25, 2002, 34,267,089 shares of the Registrant's common stock
were outstanding.

DOCUMENT INCORPORATED BY REFERENCE

Portions of the Registrant's Proxy Statement for the 2002 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. [ ]
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BENTON OIL AND GAS COMPANY

FORM 10-K

TABLE OF CONTENTS

1

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 and Russia, 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 natural gas wells, the price for oil and natural gas,
and other risks described in our 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 natural 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.

At the end of Item 1 is a glossary of terms.

ITEM 1. BUSINESS

GENERAL

Benton Oil and Gas Company is an independent energy corporation which has
been engaged in the development and production of oil and gas properties since
1989, when it was incorporated under Delaware law. We have developed significant
interests in the Bolivarian Republic of Venezuela ("Venezuela") and the Russian
Federation ("Russia"), and have acquired certain less significant interests in
other parts of the world. Our producing operations are conducted principally
through our 80 percent-owned Venezuelan subsidiary, Benton-Vinccler, C.A., which
operates the South Monagas Unit in Venezuela; and Geoilbent Ltd., a Russian
limited liability company of which we own 34 percent, which operates the North
Gubkinskoye and South Tarasovskoye Fields in West Siberia, Russia. Additionally,
we own 68 percent of the equity interest in Arctic Gas Company, of which 29
percent was subject to restrictions on transfer and 39 percent was not subject
to restrictions on transfer, as of December 31, 2001. Arctic Gas was formed to
explore and develop the Samburg and Yevo-Yakha License Blocks in the West
Siberian Basin of Russia. On February 27, 2002, we entered into a Sale and
Purchase Agreement ("Transaction") to sell our entire 68 percent interest in
Arctic Gas Company ("Proposed Arctic Gas Sale") to a nominee of the Yukos Oil
Company, a Russian oil and gas company, for $190 million plus approximately $30
million as repayment of inter-company loans owed to us by Arctic Gas. We have
expanded into other, less significant projects in China, California, and
Louisiana.

As of December 31, 2001, we had total estimated proved reserves net of
minority interest of 168.8 MMBOE, and a standardized measure of discounted
future net cash flow, before income taxes, for total proved reserves of $365.7
million. Of these totals, the South Monagas Unit represented 83.6 MMBbls and
$176.2 million, Geoilbent represented 29.6 MMBbls and $81.1 million, and Arctic
Gas (based on our 39 percent unrestricted ownership) represented 55.6 MMBOE and
$108.4 million.

As of December 31, 2001, we had total assets of $348.2 million. For the
year ended December 31, 2001, we had total revenues of $122.4 million, cash
flows from operations, before working capital changes, of $28.2 million,
earnings before interest, income taxes and depletion, depreciation and
amortization ("EBITDA") of $58.0 million and long-term debt of $221.6 million.
For the year ended December 31, 2000,

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we had total revenues of $140.3 million, cash flows from operations, before
working capital changes, of $47.3 million, EBITDA of $80.6 million and long-term
debt of $213.0 million.

We currently have significant debt principal obligations payable in 2003
($108 million) and 2007 ($105 million). Our ability to meet our debt obligations
and to reduce our level of debt depends on the implementation of our strategic
objectives, and in particular the Proposed Arctic Gas Sale. On March 22, 2002,
we were notified that the Transaction had received the requisite consents from
the Russian Ministry for Antimonopoly Policy and Support for Entrepreneurship.
On March 28, 2002, we received the first payment ($120.0 million) of the
Proposed Arctic Gas Sale proceeds. We expect that all aspects of the Transaction
will be completed by April 2002. While we have no assurance that the Transaction
will close, the net proceeds should be sufficient to retire early all of our
2003 debt service obligation. See The Proposed Arctic Gas Sale if Closed Can
Partially Reduce the Impact of Leverage in Item 7 -- Management's Discussion and
Analysis of Financial Condition and Results of Operations, and Note 16 to the
Audited Financial Statements in Item 14 -- Exhibits, Financial Statement
Schedules and Reports on Form 8-K. In the event the Proposed Arctic Gas Sale
does not close, we will evaluate alternatives with respect to our 2003 repayment
obligation. In the meantime, we believe that cash flow from operations,
supplemented by other asset sales or borrowings will be adequate to satisfy
interest payments on outstanding debt. However, general economic conditions and
financial, business and other factors affect our operations and our future
performance. Many of these factors are beyond our control.

MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS

We have taken the necessary steps to strengthen management, improve our
operations and enhance our financial flexibility. In 2001, we completed the
following:

- installed new senior management;

- redefined our strategic priorities to focus on value creation;

- initiated capital conservation steps and financial transactions,
including the Proposed Arctic Gas Sale, designed to de-leverage the
Company and improve our cash flow allowing debt retirement and
reinvestment;

- undertook a comprehensive study of our core Venezuelan asset which
focused on enhancing the value of its production;

- built the Tucupita pipeline in Venezuela to reduce transportation costs;

- sought and received relief from certain restrictive provisions of our
debt instruments;

- reduced our operating expenses, corporate overhead, moved our
headquarters to Houston and transferred engineering, geological and
geophysical activities to our overseas offices; and

- proposed a change in our name to Harvest Natural Resources, Inc.

We continue to explore means by which to maximize stockholder value. On
February 27, 2002, we entered into a Sale and Purchase Agreement ("Transaction")
to sell our entire 68 percent interest in Arctic Gas Company ("Proposed Arctic
Gas Sale") to a nominee of the Yukos Oil Company, a Russian oil and gas company,
for $190 million plus approximately $30 million as repayment of inter-company
loans owed to us by Arctic Gas. On March 22, 2002, we were notified that the
Transaction had received the requisite consents from the Russian Ministry of
Antimonopoly and Support for Entrepreneurship. On March 28, 2002, we received
the first payment ($120.0 million) of the Proposed Arctic Gas Sale proceeds.
While no assurances can be given, we expect that all aspects of the Transaction
will be completed by April 2002.

The net proceeds expected to be realized from the sale, after expenses,
taxes, and the settling of certain related claims, is estimated to be
approximately $150 million. These funds will be used, in part, to retire early
all of the $108 million of 11 5/8% senior notes, which are due in May 2003, in
accordance with their terms and without penalty. We intend to use any remaining
net proceeds and cash received from the repayment of loans to further reduce
debt from time to time, accelerate our strategic growth in Venezuela and Russia,
and for

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general corporate purposes. Retirement of all the outstanding 11 5/8% notes
eliminates $12.6 million, or $0.37 per diluted share, of annual interest expense
and should mitigate near-term concern about the Company's liquidity. These
retirements, plus the gain on sale, will allow us to fulfill our previous
commitment to restore our balance sheet strength by reducing our
debt-to-capitalization ratio from over 77% to the 41% range (see Management's
Discussion and Analysis of Financial Condition and Results of Operations of
Management, Operational and Financial Restrictions).

We possess significant producing properties in Venezuela, which we believe
have yet to be optimized, and valuable unexploited acreage in both Venezuela and
Russia. We believe the eleven new wells drilled in the South Tarasovskoye Field
since July 2001 significantly increase the value of our Geoilbent properties. In
December 2001 and January 2002, we spudded the first two wells in our seven well
Tucupita Field program in Venezuela. We are evaluating the construction of
additional processing and handling facilities and are in discussions with an
affiliate of Petroleos de Venezuela, S.A. ("PDVSA") regarding a sales contract
that may allow for the first-time sale of natural gas in Venezuela by our
affiliate.

In May 2001, we initiated a process intended to effectively extend the
maturity of the senior notes due May 1, 2003 by exchanging new 13.125 percent
senior notes due December 2007 plus warrants to purchase shares of our common
stock for each of the 2003 Notes. The exchange offer was withdrawn in July 2001.
However, in August 2001, we solicited and received the requisite consents from
the holders of both the 2003 Notes and the 2007 Notes to amend certain covenants
in the indentures governing the notes to enable Arctic Gas Company to incur
nonrecourse debt of up to $77 million to fund its oil and gas development
program. As an incentive to consent, we paid each noteholder an amount in cash
equal to $2.50 per $1,000 principal amount of notes held for which executed
consents were received. The total amount of consent fees paid to the consenting
noteholders was $0.3 million, which has been included in 2001 general and
administrative expenses.

In June 2001, we implemented a plan designed to reduce overall general and
administrative costs, including exploration overhead, at our corporate
headquarters and to transfer management oversight of geological and geophysical
activities to our overseas offices in Maturin, Venezuela and in Western Siberia
and Moscow, Russia. The reduction in general and administrative costs was
accomplished by reducing our headquarters staff and relocating our headquarters
to Houston, Texas from Carpinteria, California. For 2001, we recorded
non-recurring items of $11.4 million; $5.7 million of which are included in
general and administrative expenses, $1.7 million of which are included in
depletion, depreciation and amortization, $3.2 million in operating expenses and
$0.8 in taxes other than income. The general and administrative expenses include
$2.2 million on the withdrawn debt exchange, $2.2 million for severance and
termination benefits for 33 employees, $1.1 million for lease relinquishment
expenses and $0.2 million for relocation costs to Houston. Depletion,
depreciation and amortization included $0.9 million for the reduction in the
carrying value of fixed assets that were not transferred to Houston and $0.8
million loss on subleasing the former Carpinteria headquarters. All expenses
were paid or accrued by December 31, 2001. The accrued balance of $0.1 million
will be paid in 2002.

OPERATING STRATEGY

Our business strategy supports the steady investment, prudent risk
management and timely harvest of large hydrocarbon resources for attractive
values. For the foreseeable future, we believe our best success will be found in
Venezuela and Russia, areas in which we have significant experience and
expertise.

During 2001, our operating strategy was necessarily focused on improving
the efficiency and efficacies of our current operations in both Venezuela and
Russia. Over the years, we have benefited from the significant capital
commitment made to these areas, but have suffered financially from sub-optimal
operating, contracting and risk management practices, which, for the most part,
have been or are currently in the process of being significantly improved. In
Venezuela, we implemented new development and production plans at Benton-
Vinccler following an eight-month suspension of drilling and an extensive
reservoir study, which resulted in increased production, lower operating costs
and added confidence in our future drilling plans to extend the life and value
of the field. We have also streamlined decision making, improved internal
controls and implemented

4

industry standard techniques to mitigate geologic, operating, financial and
political risks attendant with doing business in Venezuela.

In Russia, where we are a minority owner in Geoilbent, we are attempting to
pursue a similar course with the help of other interest owners, in order to
improve operations and extend the life of the field, lower operating costs and
enhance financial results. These assets represent significant potential value
for us, but remain subject to sub-optimal operating conditions while our lack of
majority control over its operations could inhibit our ability to implement
necessary changes in management, operations or financing matters.

In both Venezuela and Russia, and in other countries around the world, the
development of local markets for natural gas represents a significant
opportunity for us. However, the development of these markets, in large part,
depends upon substantial capital investment by third parties in the
infrastructure needed to produce, gather, treat, transport, store and convert
natural gas into marketable products. While this investment is beginning to
materialize in many of these markets, it will take many years, in some
instances, to place such assets into service. We are well positioned to benefit
from the emergence of new regional gas markets in proximity to our reserves.

Our long-term strategy is to identify, access and exploit large resources
of hydrocarbons in underexploited areas around the world that can be developed
at low overall finding costs, produced at low operating costs and converted into
proved reserves, production and value. While our success is dependent upon many
factors both within and outside of our control, in order to achieve this
strategy, we must:

- continue to improve our financial flexibility and financing strategies;

- exploit our core assets in Venezuela and Russia; and

- seek and exploit new oil and natural gas resources in our core areas.

We intend to continue to seek and exploit new oil and natural gas reserves
in current areas of interest while working toward minimizing the associated
financial and operating risks. To reduce these risks, not only in seeking new
reserves, but also with respect to our existing operations, we:

- Focus Our Efforts in Areas of Low Geologic Risk: We intend to focus our
exploration and development activities only in areas of known, proven
hydrocarbons.

- Establish a Local Presence Through Joint Venture Partners and the Use of
Local Personnel: We seek to establish a local presence in our areas of
operation to facilitate stronger relationships with local government and
labor. In addition, using local personnel helps us to take advantage of
local knowledge and experience and to minimize costs. In pursuing new
opportunities, we will seek to enter at an early stage and find local
investment partners in an effort to reduce our risk in any one venture.

- Commit Capital in a Phased Manner to Limit Total Commitments at Any One
Time: We often agree to minimum capital expenditure or development
commitments at the outset of new projects, but we endeavor to structure
such commitments so that we can fulfill them over time, thereby limiting
our initial cash outlay, as well as maximize the amount of local
financing capacity to develop the hydrocarbons and associated
infrastructure.

OPERATIONS

The following table summarizes our proved reserves, drilling and production
activity, and financial operating data by principal geographic area at and for
each of the three years ended December 31. All Venezuelan reserves are
attributable to an operating service agreement between Benton-Vinccler and an
affiliate of PDVSA under which all mineral rights are owned by the Government of
Venezuela. Geoilbent and Arctic Gas Company are accounted for under the equity
method and have been included at their respective ownership interest in our
consolidated financial statements. Our year-end financial information contains
results from our Russian operations based on a twelve-month period ending
September 30. Accordingly, our results of operations for the years ended
December 31, 2001, 2000 and 1999 reflect results from Geoilbent for the twelve

5

months ended September 30, 2001, 2000 and 1999, and from Arctic Gas for the
twelve months ended September 30, 2001 and 2000.

We own 80 percent of Benton-Vinccler. The reserve information presented
below is net of a 20 percent deduction for the minority interest in
Benton-Vinccler. Drilling and production activity and financial data are
reflected without deduction for minority interest. Reserves include production
projected through the end of the operating service agreement in July 2012.

We own 34 percent of Geoilbent, which we account for under the equity
method. The following table presents our proportionate share of Geoilbent's
proved reserves, drilling and production activity, and financial operating data
for the twelve months ended September 30, 2001, 2000, and 1999.

As of December 31, 2001, 2000 and 1999, we owned, free of any sale and/or
transfer restrictions, 39, 29 and 24 percent, respectively, of the equity
interests in Arctic Gas, which we account for under the equity method. The
following table presents our proportionate share, free of sale and transfer
restrictions, of Arctic Gas's proved reserves, drilling and production activity,
and financial operating data for the twelve months ended September 30, 2001 and
2000.

SOUTH MONAGAS UNIT, VENEZUELA (BENTON-VINCCLER)

General

In July 1992, Benton and Venezolana de Inversiones y Construcciones
Clerico, C.A., a Venezuelan construction and engineering company ("Vinccler"),
signed a 20-year operating service agreement with Petroleo y Gas, S.A., an
affiliate of PDVSA to reactivate and further develop the Uracoa, Tucupita and

7

Bombal Fields. These fields comprise the South Monagas Unit. We were the first
U.S. company since 1976 to be granted such an oil field development contract in
Venezuela.

The oil and natural gas operations in the South Monagas Unit are conducted
by Benton-Vinccler, our 80 percent-owned subsidiary. The remaining 20 percent of
the outstanding capital stock of Benton-Vinccler is owned by Vinccler. Through
our majority ownership of stock in Benton-Vinccler, we make all operational and
corporate decisions related to Benton-Vinccler, subject to certain
super-majority provisions of Benton-Vinccler's charter documents related to:

- mergers;

- consolidations;

- sales of substantially all of its corporate assets;

- change of business; and

- similar major corporate events.

Vinccler has an extensive operating history in Venezuela. It provided
Benton-Vinccler with initial financial assistance and significant construction
services. Vinccler continues to provide ongoing assistance with construction
projects, governmental and labor relations.

Under the terms of the operating service agreement, Benton-Vinccler is a
contractor for PDVSA. Benton-Vinccler is responsible for overall operations of
the South Monagas Unit, including all necessary investments to reactivate and
develop the fields comprising the South Monagas 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 barrels of
oil accepted by PDVSA during the quarter, using quarterly adjusted contract
service fees per barrel. Benton-Vinccler 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
barrel of crude oil delivered. It also provides Benton-Vinccler with the right
to receive 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 barrel set forth in the agreement. The operating fee is
subject to quarterly adjustments to reflect changes in the special energy index
of the U.S. Consumer Price Index. The maximum total fee is subject to quarterly
adjustments to reflect changes in the average of certain world crude oil prices.

In December 1999, Benton-Vinccler entered into an alliance with
Schlumberger for the Uracoa field which includes reservoir modeling, drilling
and downhole electrical pumping. The alliance gives us access to Schlumberger's
technical resources and personnel and provides financial incentives for
Schlumberger based on their performance. The incentives are designed to reduce
drilling costs, improve initial production rates of new wells and increase the
average life of downhole pumps. Schlumberger maintains a full-time staff at
Benton-Vinccler's office as part of this agreement. We signed an amendment to
the alliance in 2001 whereby Schlumberger agreed to provide drilling and
completion services for new wells utilizing fixed lump-sum pricing. The amended
alliance continues to provide incentives to Schlumberger designed to improve
initial production rates of new wells and to increase the average life of the
downhole pumps.

We drilled eight oil wells in 2001. As part of our strategic shift in focus
on the value of the barrels produced, we suspended the development drilling
program for a period of approximately eight months starting in January 2001.
During this period, with the assistance of alliance partner Schlumberger, all
aspects of operations were thoroughly reviewed to integrate field performance to
date with revised computer simulation modeling and improved well completion
technology. We believe this helped to produce a streamlined and more effective
infill drilling and well workover program that is part of an overall reservoir
management strategy.

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Location and Geology

The South Monagas 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 South Monagas 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, 2001, proved reserves attributable to our Venezuelan
operations were 104,514 MBbls (83,611 MBbls net to Benton). This represented
approximately 50 percent of our proved reserves. Benton-Vinccler has been
primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field
contains 70 percent of the South Monagas Unit's proved reserves. In December
2001, Benton-Vinccler began the development of the Tucupita Field. We intend to
drill seven oil wells and two water injection wells in the Tucupita Field during
2002. Benton-Vinccler is currently reinjecting most of the associated natural
gas produced at Uracoa back into the reservoir.

Natural Gas Sale Negotiations

We are currently in discussions with PDVSA regarding the negotiation of a
contract contemplating the sale of natural gas produced from the South Monagas
Unit. Benton-Vinccler anticipates natural gas from the Uracoa and Bombal Fields
could be dedicated to PDVSA over the remaining life of the operating service
agreement. If the parties reach an agreement, construction of a pipeline,
compressor and other necessary infrastructure may be required in order to
deliver natural gas to PDVSA in accordance with agreed specifications. However,
there are no assurances that a natural gas contract will result from these
negotiations.

Drilling and Development Activity

Benton-Vinccler drilled 8 wells and had an average of 133 wells on
production in all fields in 2001.

URACOA FIELD

Benton-Vinccler has been developing the South Monagas Unit since 1992,
beginning with the Uracoa Field. The following table sets forth the Uracoa Field
drilling activity and production information for each of the quarters presented:

In 1998, we developed a geologic and reservoir simulation study which
indicated the viability of multiple additional primary infill wells in the
Uracoa Field. We believe many of these new locations are in underdeveloped sands
where the model may help to optimize well spacing and location. In the more
developed

9

areas of the field, we used the model to verify our economic assumptions
regarding infill locations. In the first quarter of 2001, we began a
comprehensive technical review of the South Monagas Unit that includes the
completion of an extensive geologic and reservoir computer simulation study
which we believe will assist in optimizing field management. The computer
simulation study, built jointly with Schlumberger, may update and extend the
1998 study performed on a portion of the Uracoa Field to the entire South
Monagas Unit. It will incorporate all new geologic and reservoir information as
well as the total production and drilling history from the more mature Uracoa
Field and the underdeveloped Tucupita and Bombal Fields. We expect several
benefits from the study including an optimum production profile of oil and gas,
a revised water and natural gas injection strategy, more efficient development
locations and improved well completion techniques. We anticipate completing a
revised Uracoa Field development plan, incorporating the results of this study,
in mid-2002.

Since 1992, we have reactivated 15 previously drilled wells and drilled 147
new wells in the Uracoa Field using improved drilling and completion techniques
that had not previously been utilized on the field. Of the new wells drilled, 6
wells were drilled as water or natural gas injector wells and an additional 6
producing wells have been converted into injection wells. Two of the drilled
injector wells were subsequently converted into producing wells.

We process the oil, water and natural gas produced from the Uracoa Field in
the Uracoa central processing unit. We ship the processed oil via pipeline to
the PDVSA custody transfer point. We treat and filter produced water, and then
re-inject it into the aquifer to assist the natural water drive. We re-inject
natural gas into the natural gas cap primarily for storage conservation. The
major components of the 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 Mcf of natural gas per day.

In August 1999, Benton-Vinccler sold its 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.

TUCUPITA AND BOMBAL FIELDS

Before becoming inactive in 1987, the Tucupita Field had been substantially
developed. It had 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 1.9 MMBbls of oil at an average rate of 987 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, we
changed the redevelopment strategy to include drilling deviated wells to allow
for more effective water shut-off. During the second half of 1998, we drilled
five deviated infill wells to target undepleted portions of the field and
reactivated an additional nine wells. All five drilled wells encountered high
oil saturations, with an average initial production rate of 922 Bbls of oil per
day. In 2001, we reactivated nine wells in Tucupita and identified seven new
well locations in what we believe are undepleted portions of the Tucupita Field,
which we anticipate drilling in 2002. As a result of our analysis of the
potential in the Tucupita Field, and for environmental and safety reasons, we
constructed a $10.3 million, 31-mile, 20,000 Bbl per day capacity oil pipeline
from Tucupita to the Uracoa central processing unit in 2001.

We are reinjecting produced water from Tucupita into the aquifer to aid the
natural water drive, and we utilize a portion of the associated natural gas to
operate a power generation facility.

To date, we have drilled one well in the Bombal Field and reactivated
another. The Bombal Field is now shut-in. We are currently evaluating the future
development plan for Bombal in light of our negotiations with PDVSA concerning
the sale of natural gas.

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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. This is the custody transfer point. The service
agreement specifies that the oil stream may contain no more than one percent
base sediment and water. Quality measurements are conducted both at
Benton-Vinccler's facilities and at PDVSA's storage facility. We installed a
continuous flow measuring unit at our facility to closely monitor the quantities
of hydrocarbons delivered to PDVSA. This flow measuring unit was completed in
January 2002. PDVSA provides Benton-Vinccler with a daily acknowledgment
regarding the amount of oil accepted during the previous day. At the end of each
quarter, Benton-Vinccler prepares an invoice to PDVSA for that quarter's
deliveries. PDVSA pays the invoice by 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.

Natural gas produced by Benton-Vinccler is currently re-injected or used as
fuel gas in operations. We are currently in negotiations with PDVSA for sale of
natural gas in the South Monagas Unit. There are no assurances that natural gas
contracts will result from these negotiations.

Employees and Community Relations

Benton-Vinccler has a highly skilled staff of predominately Venezuelan
nationals. Benton-Vinccler has also formed successful and supportive
relationships with local government agencies and communities. There are 174
local employees and 5 expatriates working at Benton-Vinccler.

Benton-Vinccler has invested in a Social Community Program that includes
medical care programs such as in ophthalmologic and dental care. From 1994 to
2001, a total of 340 eye surgeries were performed on patients ranging in age
from two to eighty-five years, solely as a result of financial assistance
provided by Benton-Vinccler. The dental program focuses on comprehensive dental
care for public school children. From 1994 to 2001, the program has involved
approximately 1,825 children. Additional social investments include sponsoring
the purchase of medicines and medical equipment in local communities within the
South Monagas Unit, as well as supporting local schools, education programs and
environmental improvements.

Health, Safety and Environment

Benton-Vinccler's health, safety and environmental policy is an integral
part of its business. Annually, improvements have been made in operating
performance, personnel safety, property protection and environmental management.
These improvements can be directly attributed to the efforts in accident
prevention programs and the training and implementation of a comprehensive
Process Safety Management System.

NORTH GUBKINSKOYE AND SOUTH TARASOVSKOYE, RUSSIA (GEOILBENT)

General

In December 1991, the joint venture agreement forming Geoilbent was
registered with the Ministry of Finance of the USSR. Geoilbent's ownership is as
follows:

- Benton owns 34 percent;

- Open Joint Stock Company Minley ("Minley") owns 66 percent.

In November 1993, the agreement was registered with the Russian Agency for
International Cooperation and Development. Geoilbent was later re-chartered as a
limited liability company. We believe that we have developed a good relationship
with our shareholder and have not experienced any disagreements on major
operational matters. Purneftegazgeologia and Purneftegas (co-founding
shareholders) contributed their interest to Minley in 2001. We are reviewing
ways to improve the operations, but we are a minority partner and therefore may
not be able to fully effect changes in operations, if indicated by our review.
Geoilbent shareholder action requires a 67 percent majority vote of its
shareholders.

11

Location and Geology

Geoilbent develops, produces and markets crude oil from the North
Gubkinskoye and South Tarasovskoye Fields in the West Siberia region of Russia,
located approximately 2,000 miles northeast of Moscow. Large proven oil and gas
fields surround all four of Geoilbent's licenses.

The North Gubinskoye Field is included inside a license block of 167,086
acres, an area approximately 15 miles long and four miles wide. The field has
been delineated with over 60 exploratory wells, which tested 26 separate
reservoirs. 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. Geoilbent is currently
flaring the produced natural gas in accordance with environmental regulations,
although it is exploring alternatives to market the natural gas.

The South Tarasovskoye Field is located a few miles southeast of North
Gubinskoye Field and straddles the eastern boundary of the Urabor Yakhinsky
exploration block acquired by Geoilbent in 1998. It is estimated a majority of
the field is situated within the block. The remaining portion of the field falls
within a license block owned by Purneftegaz. Production began in early 2001 from
a discovery well drilled close to the boundary by Purneftegaz. Only 521 of
Geoilbent's 763,558 acres in this field are reflected as proved-developed acres.

Geoilbent also holds rights to two more license blocks comprising 426,199
acres in the West Siberia region of Russia.

Drilling and Development Activity

Geoilbent commenced initial operations in the North Gubinskoye Field during
the third quarter of 1992 with the construction of a 37-mile oil pipeline and
installation of temporary production facilities. During 2001, approximately 110
wells were producing with 29 injection wells. Drilling in South Tarasovskoye
Field began at the end of May 2001. The first well was completed on July 23,
2001 for an initial production rate of 1,695 Bbls oil per day. In 2001,
Geoilbent drilled 11 wells at an average production rate of 880 Bbls oil per
day. By the end of 2001, total production from the 11 wells was 9,700 Bbls oil
per day. Plans are to drill between 50 to 60 more wells by 2005 to more fully
develop the portion of the field within the Urabor block.

The following table sets forth drilling activity and production information
for each of the quarters presented:

12

Geoilbent contracts with third parties for drilling and completion of
wells. To date, 38 previously drilled wells have been reactivated and 153 wells
have been drilled in the field. A total of 129 wells, or 84 percent, have been
completed and placed on production, 20 of which were converted to water
injection wells. Each well is drilled to an average measured depth of
approximately 9,000 feet and an average true vertical depth of 8,000 feet. The
current production facilities are operating at or near capacity and will need to
be expanded to accommodate production increases.

Geoilbent transports oil produced from the North Gubkinskoye Field to
production facilities constructed and owned by Geoilbent. It then transfers the
oil to Geoilbent's 37-mile pipeline, which transports the oil from the North
Gubkinskoye Field south to the main Russian oil pipeline network.

Geoilbent has obtained financing through a $65 million parallel loan
facility for the development of the North Gubkinskoye Field from the European
Bank for Reconstruction and Development ("EBRD") and the International Moscow
Bank. A total of $48.5 million had been advanced from the loan facility. Debt
outstanding under the facility at December 31, 2001 was $38.6 million. As of
September 30, 2001, Geoilbent was not in compliance with the current ratio
covenant but received a waiver from EBRD through March 31, 2002.

Geoilbent has reduced its 2002 capital budget to approximately $16.6
million, of which $2.7 million is for the North Gubkinskoye Field, $9.7 million
is for the South Tarakovskoye Field, $2.2 million is to carry out seismic and
related exploration activity and $2.0 million is for natural gas plant economic,
technical and feasibility studies. Geoilbent's 2002 operating budget includes
$16 million for principal payments on the loan facility. In addition, Geoilbent
had outstanding accounts payable of $26.6 million as of December 31, 2001,
primarily to contractors and vendors for drilling and construction services.

Although Geoilbent's reduced capital expenditure budget may help to
alleviate any shortfall of funds available to make payments to the banks and its
creditors as those payments come due, it is uncertain that Geoilbent's cash flow
from operations will be sufficient to do so, and it may be necessary for
Geoilbent to obtain capital contributions from its partners, including the
Company, to have sufficient funds to make these payments on a timely basis.
Although the Company may consider making such a capital contribution, there can
be no assurances that the Company will do so, nor can there be any assurances
that Geoilbent's other partner will be willing or able to do so. Under Russian
law, a creditor can force a company into involuntary bankruptcy if the company's
payments have been due for more than 90 days.

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. Trading
companies such as Rosneftegasexport handle all export oil sales. All export
sales have been paid in U.S. dollars into Geoilbent's account in Moscow.
Domestic sales are paid in Russian Rubles. During 2001, Geoilbent sold
approximately 49 percent of its production in the export market and 51 percent
in the domestic market. Excise, pipeline and other tariffs and taxes continue to
be levied on all oil producers and certain exporters, including an oil export
tariff that decreased in 2002 to $8.00 per ton (approximately $1.10 per barrel)
from 23.4 Euros per ton (approximately $2.85 per barrel). We are unable to
predict the impact of taxes, duties and other burdens for the future for our
Russian operations.

Employees; Community and Country Relations

Geoilbent employs Russian nationals almost exclusively. Presently, there
are two full-time expatriates working with Geoilbent and 700 local employees. We
have conducted community relations programs, providing medical care, training,
equipment and supplies in towns in which Geoilbent personnel reside and also for
the nomadic indigenous population which reside in the area of oilfield
operations.

13

EAST URENGOY, RUSSIA (ARCTIC GAS COMPANY)

General

See The Proposed Sale of Arctic Gas Company, if Closed, Will Reduce the
Impact of Leverage in Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations, and Note 16 to the Audited
Financial Statements in Item 14 -- Exhibits, Financial Statement Schedules and
Reports on Form 8-K.

Arctic Gas Company, formerly Severneftegaz, was formed in 1992 as a private
company to explore and develop the Samburg and Yevo-Yakha License Blocks. The
Samburg and Yevo-Yakha License Blocks are located within the West Siberian
Basin, the world's largest sedimentary basin, which contains a significant
portion of the world's natural gas reserves. Both license blocks are on the
eastern flank of the giant Urengoy natural gas field, which currently produces
hydrocarbons from Cenomanian reservoirs. Under the terms of agreements signed in
April 1998, we acquired a 40 percent interest in Arctic Gas in return for
providing or arranging up to $100 million of credit financing for the project.
Our agreements impose restrictions on the sale and transfer of these shares
subject to disbursements under the credit financing and provide that for every
$2.5 million of credit made available, 1 percent of the interest will be
released from the restrictions.

As of December 31, 2001, we had provided $28.5 million of credit, of which
$28.1 million had been applied to the release of restrictions on the shares. As
a result, we removed restrictions from shares representing an approximate 11
percent equity interest. From 1998 through December 2001, we separately
purchased shares representing an additional 28 percent equity interest not
subject to any sale or transfer restrictions. Including the additional purchased
shares, as of December 31, 2001, we owned a total of 68 percent of the voting
shares of Arctic Gas, of which 39 percent was not subject to restrictions.

The following table summarizes our ownership interests of Arctic Gas
Company:

In February 2002, we announced the Proposed Arctic Gas Sale. On March 22,
2002, we were notified that the Transaction had received the requisite consents
from the Russian Ministry for Antimonopoly Policy and Support for
Entrepreneurship. On March 28, 2002, we received the first payment ($120.0
million) of the Proposed Arctic Gas Sale proceeds.

Location and Geology

The Samburg and Yevo-Yakha License Blocks comprise 794,972 acres and are
situated approximately 150 miles north of our Geoilbent affiliates' operations
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 (over 90 wells) on the Samburg and
Yevo-Yakha licenses has resulted in the discovery of major resources of natural
gas, condensate and oil. The primary reservoirs of these fields are currently
being produced in both the adjacent Urengoy Field and Rospan Block.

Drilling and Development Activity

Arctic Gas has reactivated 8 previously drilled oil wells through March 23,
2002. We are trucking oil to storage facilities where it is collected for sale.
Arctic Gas is currently producing approximately 2,700 Bbls of oil per day.

14

The following table sets forth reactivation activity and production
information for each of the quarters presented:

Arctic Gas is currently planning for a Samburg oil and natural gas pilot
development project. The pilot project calls for:

- drilling new wells;

- installing natural gas processing facilities; and

- connecting into the export pipeline system.

The Arctic Gas blocks are located in the heart of the Urengoy/Yamburg
producing and support infrastructure region and are well situated for
development. Natural gas export trunklines are located 11 kilometers from the
blocks. Arctic Gas and Gazprom have entered into agreements to allow access to
existing oil, liquids and natural gas pipelines and facilities that could
potentially result in product sales to domestic and export markets. See Note 16
to the Audited Financial Statements in Item 14 -- Exhibits, Financial Statement
Schedules and Reports on Form 8-K. Arctic Gas had entered into contracts with
various parties concerning the export of natural gas. All natural gas contracts
have been cancelled pursuant to the Proposed Arctic Gas Sale.

Further development activities are subject to the pace and scope of Arctic
Gas's internally generated funds and to our ability to provide or arrange
further funding.

Employees; Community and Country Relations

Arctic Gas is a Russian company that employs Russian nationals almost
exclusively. Presently, there are 2 full-time expatriates working with Arctic
Gas and 161 local employees. We have conducted community relations programs in
Russia, providing medical care, training, equipment and supplies in towns in
which Arctic Gas personnel reside and also for the nomadic indigenous population
which reside in the area of oilfield operations.

WAB-21, SOUTH CHINA SEA (BENTON OFFSHORE CHINA COMPANY)

General

In December 1996, we acquired Crestone Energy Corporation, a privately held
company headquartered in Denver, Colorado, subsequently renamed Benton Offshore
China Company. Its principal asset is a petroleum contract with China National
Offshore Oil Corporation ("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, 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 dispute has lasted for many years, and
there has been limited exploration and no development activity in the area under
dispute.

15

We cannot predict how or when, if at all, this dispute will be resolved or
whether it would result in our interest being reduced.

Location and Geology

The WAB-21 contract area is located approximately 50 miles southeast of the
Dai Hung (Big Bear) Oil Field. The block is adjacent to British Petroleum's
giant natural 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 hydrocarbon reserves in possible multiple pay
zones.

Drilling and Development Activity

Due to the sovereignty issues, we have been unable to pursue an exploration
program during phase one of the contract. As a result, we have obtained
extensions, with the current extension in effect until May 31, 2003.

DOMESTIC OPERATIONS

In April and May 2000, we entered into agreements with Coastline Energy
Corporation ("Coastline") for the purpose of acquiring, exploring and developing
oil and natural gas prospects both onshore and in the state waters of the Gulf
Coast states of Texas, Louisiana and Mississippi. We acquired a 100 percent
working interest in the Lakeside Exploration Prospect in Cameron Parish,
Louisiana. We farmed out 90 percent of the working interest in the prospect for
$0.5 million cash and a 16.2 percent carried interest in the first well. We
anticipate that drilling of the well may commence in 2002. The agreement with
Coastline was terminated on August 31, 2001. However, certain ongoing operations
related to the Lakeside Exploration Prospect are conducted by Coastline on a
consulting basis.

In March 1997, we acquired a 40 percent participation interest in three
California State offshore oil and natural gas leases ("California Leases") from
Molino Energy Company, LLC ("Molino Energy"), which held 100 percent 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 percent participation interest in the California Leases, we became the
operator of the project and agreed to pay 100 percent of the first $3.7 million
and 53 percent 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, we
entered into an agreement to acquire Molino Energy's interest in the California
Leases in exchange for the release of their joint interest billing obligations.
In the fourth quarter of 1999, we decided to focus our capital expenditures on
existing producing properties and fulfilling work commitments associated with
our other properties. Because we had no firm approved plans to continue drilling
on the California Leases and the 2199 #7 exploratory well did not result in
commercial reserves, we 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. However, we continue to
evaluate the prospect for potential future drilling activities.

16

ACTIVITIES BY AREA

The following table summarizes our consolidated activities by area. Total
Assets represents all assets including long-lived assets accounted under the
equity method:

RESERVES

Estimates of our proved reserves as of December 31, 2001 and 2000 were
prepared by Ryder Scott Company, LP, independent petroleum engineers. In prior
years, reserve estimates were prepared by us and audited by Huddleston & Co.,
Inc., independent petroleum engineers. The following table sets forth
information regarding estimates of proved reserves at December 31, 2001. The
Venezuelan information includes reserve information net of a 20 percent
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.
Although we estimate that there are substantial natural gas reserves in the
Benton-Vinccler properties in Venezuela and the license blocks held by
Geoilbent, no natural gas reserves have been recorded as of December 31, 2001
because of a lack of sales and/or transportation contracts in place. Geoilbent
and Benton-Vinccler are currently evaluating alternatives to market this natural
gas. Natural gas proved reserves have been recognized for Arctic Gas, which has
transportation and marketing contracts in place. The marketing contracts were
cancelled in anticipation of the Proposed Arctic Gas Sale. See Note 16 to the
Audited Financial Statements in Item 14 -- Exhibits, Financial Statement
Schedules and Reports on Form 8-K. The cancellation will have an impact on the
Equity Affiliate-Russia reserves found on Table IV -- Quantities of Oil and
Natural Gas Reserves.

- ---------------

(1) Based on 39 percent ownership not subject to restrictions as of December 31,
2001.

17

Estimates of commercially recoverable oil and natural 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 63
percent of our total proved reserves were undeveloped as of December 31, 2001.

Therefore, the following costs will likely vary from our estimates and such
variances may be material:

- actual production;

- oil sales;

- severance and excise taxes;

- export tariffs;

- development expenditures;

- workover and remedial expenditures;

- abandonment expenditures; and

- operating expenditures.

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 and natural gas;

- 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 and natural gas 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 percent discount factor, which is required by the SEC 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 natural 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

18

December 31, 2001, we reported $365.7 million of discounted future net cash
flows before income taxes from proved reserves based on the SEC's required
calculations.

PRODUCTION, PRICES AND LIFTING COST SUMMARY

In the following table we have set forth by country our net production,
average sales prices and average lifting costs for the years ended December 31,
2001, 2000 and 1999. The presentation for Venezuela includes 100 percent of the
production, without deduction for minority interest. Geoilbent (34 percent
ownership) and Arctic Gas (39 percent, 29 percent and 24 percent ownership not
subject to any sale or transfer restrictions at December 2001, 2000 and 1999,
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, our
results of operations for the years ended December 31, 2001, 2000 and 1999
reflect results from Geoilbent for the twelve months ended September 30, 2001,
2000 and 1999, and from Arctic Gas for the twelve months ended September 30,
2001 and 2000.

REGULATION

General

Our operations are affected by political developments and laws and
regulations in the areas in which we operate. In particular, oil and natural gas
production operations and economics are affected by:

- change in governments;

- price and currency controls;

- limitations on oil and natural gas production;

- world demand for crude oil;

- tax and other laws relating to the petroleum industry;

- changes in such laws; and

- changes in administrative regulations and the interpretation 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 natural gas wastes, or otherwise relating to the protection
of the environment, may affect our operations and costs. In any country in which
we may do business, the oil and natural gas industry legislation and agency
regulation is periodically changed for a variety of political, economic,
environmental and other reasons. Numerous governmental departments and agencies

19

issue rules and regulations binding on the oil and natural gas industry, some of
which carry substantial penalties for the failure to comply. The regulatory
burden on the oil and natural gas industry increases our 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 natural gas
in the field and water disposal were $0.1 million in 2001 and $1.1 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 and Arctic Gas submit annual production and development plans,
which include information necessary for permits and approvals for their planned
drilling, seismic and operating activities, to local and regional governments
and to the Ministry of Fuel and Energy and the Ministry of Natural Resources.
They also submit annual production targets and quarterly export nominations for
oil pipeline transportation capacity to the Ministry of Fuel and Energy.
Geoilbent and Arctic Gas are 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 and Arctic Gas must
file operating and financial compliance reports with several agencies, including
the Ministry of Fuel and Energy, Ministry of Natural Resources, Committee for
Technical Mining Monitoring and the State Customs Committee.

Russian companies are subject to a statutory income tax rate of up to 35
percent and are subject to various other tax burdens and tariffs. Excise,
pipeline and other tariffs and taxes continue to be levied on all oil producers
and certain exporters, including an oil export tariff that decreased to $8.00
per ton (approximately $1.10 per barrel) from 23.4 Euros per ton (approximately
$2.85 per barrel). We are unable to predict the impact of taxes, duties and
other burdens in the future for our Russian operations.

DRILLING, ACQUISITION AND FINDING COSTS

From commencement of operations through December 31, 2001, we added, net of
production and property sales, approximately 189.8 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 $2.34 per BOE. Our estimate
of future development costs for our undeveloped proved reserves at December 31,
2001 was $1.96 per BOE. The estimated future development costs are based upon
our anticipated cost of developing our non-producing proved reserves, which
costs are calculated using historical costs for similar activities.

For acquisitions of leases and producing properties, development and
exploratory drilling, production facilities and additional development
activities such as workovers and recompletions, we spent approximately
(excluding our share of capital expenditures incurred by equity affiliates):

- $44 million during 2001;

- $50 million during 2000; and

- $33 million during 1999.

20

We have drilled or participated in the drilling of wells as follows:

- ---------------

(1) The information related to producing wells reflects wells we drilled, wells
we participated in drilling and producing wells we acquired.

At December 31, 2001, we participated in the drilling of 39 wells in
Russia.

All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We do not directly own or operate any drilling
equipment. Geoilbent does own components of the rigs it employs.

Acreage

The following table summarizes the developed and undeveloped acreage that
we owned, leased or had under concession as of December 31, 2001:

- ---------------

(1) Russia includes 794,972 gross acres related to Arctic Gas, which is included
based on a 39 percent ownership interest.

COMPETITION

We encounter 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 our competitors have financial
resources, staffs and facilities substantially greater than ours.

21

ENVIRONMENTAL REGULATION

We are subject to environmental regulations administered by foreign
governments, their agencies, or other international organizations. We are
committed to the protection of the environment and believe we are in substantial
compliance with the applicable laws and regulations. However, regulatory
requirements change and become more stringent, and there can be no assurance
that future regulations will not have a material adverse effect on our financial
position.

EMPLOYEES

At December 31, 2001, we had 19 full-time employees, augmented from
time-to-time with independent consultants, as required. Benton-Vinccler had 174
employees, Geoilbent had 700 employees and Arctic Gas had 161 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 and
Arctic Gas have obtained certain documentation from appropriate regulatory
agencies in Russia which we believe is adequate to establish their right to
develop, produce and market oil and natural gas from their fields.

The WAB-21 petroleum contract covers 6.2 million acres in the South China
Sea, with an option for another 1.0 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 our interest being
reduced.

As is customary in the oil and natural gas industry, we make a limited
review of title to farm out acreage and to undeveloped U.S. oil and natural gas
leases upon execution of the contracts and leases. Prior to the commencement of
drilling operations, a thorough drillsite title examination is conducted and
curative work is performed with respect to significant defects. We follow the
practice of obtaining title opinions on our domestic producing properties and
believe that we have satisfactory title to such properties in accordance with
standards generally accepted in the oil and natural gas industry. Our oil and
natural gas properties are subject to customary royalty interests, liens for
current taxes, and other burdens which we believe do not materially interfere
with the use of or affect the value of such properties.

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,

22

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 natural 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.

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 natural 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 natural 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

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Reserves are estimated assuming that oil and natural gas prices and production
costs remain constant. The resulting stream of oil sales is then discounted at
the rate of 10 percent per year to obtain a present value.

Undeveloped Acreage. "Undeveloped Acreage" is oil and natural 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

In July 2001, we leased for three years office space in Houston, Texas for
approximately $11,000 per month. We lease 17,500 square feet of space in a
California building that we no longer occupy under a lease agreement that
expires in December 2004; all of this office space has been subleased for rents
that approximate our lease costs.

ITEM 3. LEGAL PROCEEDINGS

On February 17, 1998, the WRT Creditors Liquidation Trust ("WRT Trust")
filed suit in the United States Bankruptcy Court, Western District of Louisiana
against us 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 commenced on May 1,
2000 that concluded at the end of August 2000, and post trial briefs were filed.
In August 2001, a favorable decision was rendered in BOGLA's favor denying any
and all relief to the WRT Trust. The WRT Trust has filed a Notice of Appeal with
the Bankruptcy Court; however, we believe that the appeal will result in an
outcome consistent with the court's prior decision.

From 1996 through 1998, we made unsecured loans to our then Chief Executive
Officer, A.E. Benton, bearing interest at the rate of 6 percent per annum. We
subsequently obtained a security interest in Mr. Benton's shares of stock and
stock options. 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. In February 2000, we entered into a
separation agreement and a consulting agreement with Mr. Benton pursuant to
which we retained Mr. Benton as an independent contractor to perform certain
services for us. During 2001, we paid Mr. Benton $116,833, and have paid a total
of $536,545 from February 2000 through May 11, 2001 for services performed under
the consulting agreement. On May 11, 2001, Mr. Benton and the Company entered
into a settlement and release agreement under which the consulting agreement was
terminated and Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the repayment of our loans to him. We
currently continue to retain our security interest in Mr. Benton's 600,000
shares of our stock and in his stock options, and we have the right to vote the
shares owned by him and to direct the exercise of his options. Repayment of our
loans to Mr. Benton may be achieved through Mr. Benton's liquidation of certain
real and personal property assets and a phased liquidation of stock resulting in
Mr. Benton's exercise of his stock options. The amount that we eventually
realize, and the timing of receipt of payments will depend upon the timing and
results of the liquidation of Mr. Benton's assets. The amount of Mr. Benton's
indebtedness to us is currently approximately $6.5 million. The consulting
agreement provides that if we close the Proposed Arctic Gas Sale, Mr. Benton
will be entitled to receive two percent of our net after-tax cash receipts,
actually received by us in the U.S., resulting from the Proposed Arctic Gas
Sale, excluding any repayment of indebtedness or advances by us to Arctic Gas.
The consulting agreement further provides that under his proposed bankruptcy
plan of reorganization, Mr. Benton will pay five percent of such amounts to us.
Based upon information provided by Mr. Benton's bankruptcy counsel, we
anticipate that under the bankruptcy plan of reorganization that Mr. Benton will
propose, we will receive $1.7 million. This amount does not include the amounts
that we will realize from the exercise of Mr. Benton's options and the
subsequent sale of the resulting shares, nor does it include the net proceeds
that we will receive from the sale of Mr. Benton's 600,000 shares of our stock.

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In the normal course of our business, there are various other legal
proceedings outstanding. In the opinion of management, these proceedings will
not have a material adverse effect on our financial position, results of
operations or liquidity.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

During the three month period ended December 31, 2001, no matter was
submitted to a vote of security holders.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

Our Common Stock has traded on the New York Stock Exchange ("NYSE") since
April 29, 1997 under the symbol "BNO." As of December 31, 2001, there were
34,114,089 shares of Common Stock outstanding held of record by approximately
947 stockholders. The following table sets forth the high and low sales prices
for our Common Stock reported by the NYSE.

On March 25, 2002, the last sales price for the Common Stock as reported by
NYSE was $4.03 per share.

Our policy is to retain earnings to support the growth of our business.
Accordingly, our Board of Directors has never declared cash dividends on our
Common Stock, and our indentures currently restrict the declaration and payment
of any cash dividends.

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ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

SELECTED CONSOLIDATED FINANCIAL DATA

The following table sets forth our selected consolidated financial data for
each of the years in the five-year period ended December 31, 2001. The selected
consolidated financial data have been derived from, and should be read in
conjunction with, our annual audited consolidated financial statements,
including the notes thereto. Our year-end financial information contains results
from our Russian operations based on a twelve-month period ending September 30.
Accordingly, our results of operations for the years ended December 31, 2001,
2000, 1999 and 1998 reflect results from Geoilbent for the twelve months ended
September 30, 2001, 2000, 1999 and 1998, and from Arctic Gas for the twelve
months ended September 30, 2001, 2000 and 1999.

- ---------------

(1) No cash dividends were paid during the periods presented.

(2) As discussed in Note 1 to the Financial Statements, in 1999 we changed our
method of reporting our investment in Geoilbent to the equity method.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS

We have taken the necessary steps to strengthen management, enhance our
financial flexibility, and improve our operations. In 2001, we completed the
following:

- installed new senior management;

- redefined our strategic priorities to focus on value creation;

- initiated capital conservation steps and financial transactions,
including the Proposed Arctic Gas Sale, designed to de-leverage the
Company and improve our cash flow for reinvestment;

- undertook a comprehensive study of our core Venezuelan asset, which
focused on enhancing the value of its production;

- pursued additional financing to accelerate the commercial development of
our Russian assets;

- built the Tucupita pipeline in Venezuela to reduce transportation costs;

- sought and obtained relief from certain restrictive provisions of our
debt instruments;

- reduced our corporate overhead, moved our headquarters to Houston and
transferred engineering, geological and geophysical activities to its
overseas offices; and

- proposed a change in our name to Harvest Natural Resources, Inc.

We continue to explore means by which to maximize stockholder value.

On February 27, 2002, we entered into a Sale and Purchase Agreement
("Proposed Arctic Gas Sale") to sell our entire 68 percent stock ownership
interest in Arctic Gas Company to a nominee of the Yukos Oil Company for $190
million. We will also receive approximately $30 million as repayment of
intercompany loans owed to us by Arctic Gas. We intend to use a portion of the
net proceeds to retire all of the $108 million outstanding 11 5/8 percent senior
notes in accordance with their terms. We intend to use any remaining net
proceeds and cash received from the repayment of loans to further reduce debt
from time to time, accelerate the strategic growth of its assets in Venezuela
and Russia and for general corporate purposes. On March 22, 2002, we were
notified that the Transaction had received the requisite consents from the
Russian Ministry for Antimonopoly Policy and Support for Entrepreneurship. On
March 28, 2002, we received the first payment ($120.0 million) of the Proposed
Arctic Gas Sale proceeds. However, in the event that the Transaction does not
close, we will be required to review additional strategic alternatives to repay
the $108 million of 11 5/8 percent senior notes due in May 2003, including, but
not limited to, selling all or part of our existing assets in Venezuela and
Russia, restructuring our debt, some combination thereof, or the selling of the
Company. However, no assurance can be given that any of these steps can be
successfully completed or that we ultimately will determine that any of the
steps should be taken. The Pro Forma adjustments reflect a net gain after tax of
$92.0 million, which utilizes our $136.0 million net operating loss. The cash
available after tax is used to purchase the $108.0 million 11 5/8 percent senior
notes at par.

In the event the Proposed Arctic Gas Sale closes, the Supplemental
Unaudited Pro Forma Condensed Balance Sheet as of December 31, 2001 shown below
illustrates the impact to the Company.

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BENTON OIL AND GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL UNAUDITED PRO FORMA CONDENSED BALANCE SHEET

- ---------------

(1) To record gain on sale of 68 percent interest in Arctic Gas Company, to
repay intercompany debt and to repay $108 million of 11 5/8 percent senior
notes.

SEE NOTE 16 TO THE AUDITED FINANCIAL STATEMENTS IN ITEM 14 -- EXHIBITS,
FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

As part of the Proposed Arctic Gas Sale, we have arranged a credit facility
of up to $100 million for Arctic Gas. In the event that the Proposed Arctic Gas
Sale does not close, we will request Arctic Gas to immediately repay this
facility.

We possess significant producing properties in Venezuela, which we believe
have yet to be optimized, and valuable unexploited acreage in both Venezuela and
Russia. We believe the eleven new wells drilled in the South Tarasovskoye Field
since July 2001 may significantly increase the value of our Geoilbent
properties. In December 2001 and January 2002, we spudded the first two wells in
our seven well Tucupita field program in Venezuela. We are evaluating the
construction of additional processing and handling facilities and are in
discussions with PDVSA to negotiate a sales contract that will allow for the
first-time sale of natural gas in Venezuela by our affiliate.

In May 2001, we initiated a process intended to effectively extend the
maturity of the senior notes due May 1, 2003 by exchanging new 13.125 percent
senior notes due December 2007 plus warrants to purchase shares of our common
stock for each of the 2003 Notes. The exchange offer was withdrawn in July 2001.
However, in August 2001, we solicited and received the requisite consents from
the holders of both the 2003 Notes and the 2007 Notes to amend certain covenants
in the indentures governing the notes to enable Arctic Gas Company to incur
nonrecourse debt of up to $77 million to fund its oil and gas development
program. As an incentive to consent, we paid each noteholder an amount in cash
equal to $2.50 per $1,000 principal amount of notes held for which executed
consents were received. The total amount of consent fees paid to the consenting
noteholders was $0.3 million, which has been included in general and
administrative expenses.

In June 2001, we implemented a plan designed to reduce overall general and
administrative costs, including exploration overhead, at our corporate
headquarters and to transfer management oversight of geological and geophysical
activities to our overseas offices in Maturin, Venezuela and in Western Siberia
and

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Moscow, Russia. The reduction in general and administrative costs was
accomplished by reducing our headquarters staff and relocating our headquarters
to Houston, Texas from Carpinteria, California. For 2001, we recorded
non-recurring items of $11.4 million, $5.7 million of which are included in
general and administrative expenses, $1.7 million of which are included in
depletion, depreciation and amortization, $3.2 million in operating expenses and
$0.8 million in taxes other than income. The general and administrative expenses
include $2.2 million on the failed debt exchange, $2.2 million for severance and
termination benefits for 33 employees, $1.1 million for lease relinquishment
expenses, and $0.2 million for relocation costs to Houston. Depletion,
depreciation and amortization included $0.9 million for the reduction in the
carrying value of fixed assets that were not transferred to Houston and $0.8
million loss on subleasing the former Carpinteria headquarters. All expenses
were paid by December 31, 2001.

Geoilbent has reduced its 2002 capital budget to approximately $16.6
million, of which $2.7 million is for the North Gubkinskoye Field, $9.7 million
is for the South Tarakovskoye Field, $2.2 million is to carry out seismic and
related exploration activity and $2.0 million is for natural gas plant economic,
technical and feasibility studies. Geoilbent's 2002 operating budget includes
$16 million for principal payments on the loan facility. In addition, Geoilbent
had outstanding accounts payable of $26.6 million as of December 31, 2001,
primarily to contractors and vendors for drilling and construction services.

Although Geoilbent's reduced capital expenditure budget may help to
alleviate any shortfall of funds available to make payments to the banks and its
creditors as those payments come due, it is uncertain that Geoilbent's cash flow
from operations will be sufficient to do so, and it may be necessary for
Geoilbent to obtain capital contributions from its partners, including the
Company, to have sufficient funds