HARVEST NATURAL RESOURCES INC - 10-K Annual Report

Back to GetFilings.com

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

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

FORM 10-K

(MARK ONE)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002,

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NO.: 1-10762

HARVEST NATURAL RESOURCES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

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

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. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes X No
----------- ----------

State the aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the price at which the common equity
was last sold, or the average bid and asked price of such common equity as of
the last business day of the registrant's most recently completed second fiscal
quarter, June 28, 2002: $174,945,360.

Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practical date. Class: Common Stock, par value
$0.01 per share, on March 21, 2003, shares outstanding: 35,216,211.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant's Proxy Statement for the 2003 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.

HARVEST NATURAL RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

Page
----

Part I

Item 1. Business............................................................................... 2
Item 2. Properties............................................................................. 18
Item 3. Legal Proceedings...................................................................... 18
Item 4. Submission of Matters to a Vote of Security Holders ................................... 18

Part II

Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters..................................................... 19
Item 6. Selected Financial Data................................................................ 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................................. 21
Item 7A. Quantitative and Qualitative Disclosures about
Market Risk......................................................................... 36
Item 8. Financial Statements and Supplementary Data............................................ 37
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ............................................. 37

Part III

Item 10. Directors and Executive Officers of the Registrant .................................... 38
Item 11. Executive Compensation................................................................. 38
Item 12. Security Ownership of Certain Beneficial
Owners and Management and
Related Stockholder Matters......................................................... 38
Item 13. Certain Relationships and Related Transactions ........................................ 38
Item 14. Controls and Procedures................................................................ 38

Part IV

Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K................................................................. 40

Financial Statements...................................................................................... S-1

Signatures................................................................................................ S-37

1

PART I

Harvest Natural Resources, Inc. ("Harvest" or 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",
"anticipate", "expect", "believes", "goals", "projects", "plans", "anticipates",
"estimates", "should", "could", "assume" and similar expressions are intended to
identify forward-looking statements. In accordance with the provisions of the
Private Securities Litigation Reform Act of 1995, we caution you that important
factors could cause actual results to differ materially from those in the
forward-looking statements. Such factors include our substantial concentration
of operations in Venezuela, the political and economic risks associated with
international operations, the anticipated future development costs for our
undeveloped proved reserves, the risk that actual results may vary considerably
from reserve estimates, the dependence upon the abilities and continued
participation of certain of our key employees, the risks normally incident to
the operation and development of oil and gas properties and the drilling of oil
and natural gas wells, the availability of materials and supplies necessary to
projects and operations, the price for oil and natural gas and related financial
derivatives, changes in interest rates, basis risk and counterparty credit risk
in executing commodity price risk management activities, the Company's ability
to acquire oil and gas properties that meet its objectives, changes in operating
costs, overall economic conditions, political stability, civil unrest, acts of
terrorism, currency and exchange risks, currency controls, changes in existing
or potential tariffs, duties or quotas, 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

Harvest Natural Resources, Inc. is an independent energy company
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") through our equity affiliate, and have undeveloped acreage
offshore China. Our producing operations are conducted principally through our
80 percent-owned Venezuelan subsidiary, Benton-Vinccler, C.A.
("Benton-Vinccler"), which operates the South Monagas Unit in Venezuela; and
Limited Liability Company Geoilbent ("Geoilbent"), a Russian company of which we
own 34 percent and which operates the North Gubkinskoye and South Tarasovskoye
Fields in West Siberia, Russia. On February 27, 2002, we entered into a Sale and
Purchase Agreement to sell our entire 68 percent interest in Arctic Gas Company
("Arctic Gas"), 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 (the "Arctic Gas Sale"). On April
12, 2002, we completed the Arctic Gas Sale and recognized a gain of $144.0
million ($93.6 million after tax). From December 14, 2002 through February 6,
2003, no sales of our Venezuelan oil production were made because of Petroleos
de Venezuela, S.A.'s ("PDVSA") inability to accept our oil due to the national
civil work stoppage in Venezuela. In restoring production, we encountered
problems with some of our wells, but we do not believe the associated costs will
be material. By the end of March 2003, our average production was approximately
24,000 barrels of oil per day. On February 5, 2003, the Venezuelan government
imposed currency controls. See Item 7 - Management's Discussion and Analysis of
Financial Conditions and Results of Operations for a complete description of
these events.

As of December 31, 2002, we had total estimated proved reserves, net of
minority interest and including our share of equity affiliates, of 127.3 MMBOE,
and a standardized measure of discounted future net cash flow, before income
taxes, for total proved reserves of $526.7 million. Of these totals, our
interests in the South Monagas Unit represented 102.5 MMBOE and $481.3 million,
and our equity interest in Geoilbent represented 24.8 MMBbls and $45.4 million,
respectively.

As of December 31, 2002, we had total assets of $335.2 million. For the
year ended December 31, 2002, we had total revenues of $126.7 million, net cash
provided by operating activities of $42.6 million, and long-term debt of

2

$104.7 million. For the year ended December 31, 2001, we had total revenues of
$122.4 million, net cash provided by operating activities of $36.6 million, and
long-term debt of $221.6 million.

AVAILABLE INFORMATION

We file annual, quarterly, and current reports, proxy statements, and
other documents with the SEC under the Securities Act of 1934. The public may
read and copy any materials that we file with the SEC at the SEC's Public
Reference Room at 450 Fifth Street, NW, Washington, DC 20549. The public may
obtain information on the operation of the Public Reference Room by calling the
SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains
reports, proxy and information statements, and other information regarding
issuers, including the Company, that file electronically with the SEC. The
public can obtain any documents that we file with SEC at http://www.sec.gov.

We also make available, free of charge on or through our Internet
website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly
Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments
to those reports filed or furnished pursuant to Section 13(a) of the Exchange
Act as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the SEC. In addition, the Company has adopted a code of
ethics that applies to all of its employees, including its chief executive
officer, principal financial officer and principle accounting officer. The text
of the code of ethics has been posted on the Governance section of the Company's
website.

OPERATING STRATEGY

Our business strategy supports the steady investment, prudent risk
management and timely development of our large hydrocarbon resources. 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. Near term,
our strategy is focused on improving the realization of value from our current
operations in both Venezuela and Russia. Investments in Venezuela and Russia are
exposed to significant political risks.

In Venezuela, we intend to continue to seek cost effective increases in
production to extend the life and value of our fields. Completing a gas project
in the fourth quarter of 2003 within budget is an important part of this
strategy because it creates a new source of revenues from sales of natural gas.
We are also looking for ways to diversify our cash flow as events in Venezuela
demonstrated the benefits of country risk diversification of our cash flow
sources when we lost six weeks of production.

Our Russian operations are an important element of our diversification
strategy. We and the majority share owner in Geoilbent continue to strive to
improve operations and monetize the value of the fields by lowering operating
costs and enhancing financial results. The Geoilbent assets represent
significant potential value for us, but remain subject to sub-optimal operating
conditions while our lack of majority control over its operations inhibits our
ability to implement necessary changes in management, operations or financing
matters to fully realize the potential of Geoilbent's assets. In addition, our
financial results have been significantly hampered by low Russian domestic oil
prices while world oil prices have reached multi-year high levels. Geoilbent's
independent accountants have indicated in their report that substantial doubt
exists regarding Geoilbent's ability to meet its debts as they become due and
continue as a going concern. An important part of our near-term strategy is to
establish and implement a plan to maximize the value of our investment in
Geoilbent by improving its operations, achieving a control position or selling
our minority ownership interest.

We believe that Russia has opportunities and that we, as an independent
oil and gas operator, can exploit using Western management and operating
techniques. The overall goal is to add undeveloped or underdeveloped resources
of oil and gas. Through phased investment, we can then increase and capture the
long-term value of the asset. We seek significant, legacy assets, with a
controlling ownership interest in partnership with local industry partners.
These partners must understand and be familiar with the asset and area's working
environment.

Our long-term strategy is founded on three guiding principles: Enable,
Manage Risk and Value Harvest. We Enable by using our experience and skills to
identify, access and exploit large known resources of hydrocarbons in
underexploited areas that can be developed at low overall finding costs,
produced at low operating costs and converted into proved reserves, production
and value. We Manage Risk by controlling or mitigating the many factors within
our

3

control, such as continuing to improve our operating risks, access to markets
and financing flexibility. We Value Harvest our existing assets by rapid
development to convert underdeveloped hydrocarbons into cash.

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:

o Focus Our Efforts in Areas of Low Geologic Risk: We intend to focus our
activities only in areas of large known but undeveloped oil and gas
resources.

o 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.

o 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.

o Limit Exploration Activities: We do not engage in exploration except in
conjunction with the expansion of an existing reservoir.

Our ability to successfully execute our strategy is subject to
significant risks including, among other things, operating risks, political
risks and financial risks. Operating risks include our ability to 1) maintain
optimal production, 2) achieve maximum reserve recovery and 3) maintain our cost
structure on an economically favorable basis, particularly in Geoilbent in which
we are a minority owner. Political risks in Venezuela are significant, and while
currently partially abated, could again have a negative influence on our
operations and our financial flexibility. In Russia, the oil and gas business is
evolving, but remains subject to local laws and customs, local market operation
and powerful domestic oil and gas companies. Our company is also solely
dependent upon sales of oil and gas, once the Venezuelan gas project is
completed, to fund our operations and service our debt requirements.
Interruptions in Benton-Vinccler's production and cash flow would erode our
financial flexibility and hinder our ability to execute our operating strategy.
In addition, Venezuela recently imposed foreign currency exchange controls which
could increase our costs of operations.

OPERATIONS

The following table summarizes our proved reserves, drilling and
production activity, and financial operating data by principal geographic area
at the end of each of the three years ending December 31, 2002. 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. Geoilbent and Arctic Gas are accounted for under the
equity method and have been included at their respective ownership interests 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, 2002, 2001 and 2000 reflect results from Geoilbent for the twelve
months ended September 30, 2002, 2001 and 2000, and from Arctic Gas, until it
was sold on April 12, 2002, 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 2012.

4

BENTON-VINCCLER
--------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------
2002 2001 2000
---------- ---------- ----------
(DOLLARS IN 000's)

RESERVE INFORMATION
Proved reserves (MBOE) 102,534 83,611 98,431
Discounted future net cash flow attributable to proved
reserves, before income taxes $ 481,284 $ 176,210 $ 368,464
Standardized measure of future net cash flows $ 317,799 $ 163,328 $ 284,549
DRILLING AND PRODUCTION ACTIVITY:
Gross wells drilled 13 8 26
Average daily production (Bbls) 26,598 26,788 25,585
FINANCIAL DATA:
Oil revenues $ 126,731 $ 122,386 $ 139,890
Expenses:
Operating expenses and taxes other than on income 31,608 42,175 46,848
Depletion 22,685 21,175 15,708
Income tax expense 4,866 9,083 20,307
---------- ---------- ----------
Total expenses 59,159 72,433 82,863
---------- ---------- ----------
Results of operations from oil and natural gas
producing activities $ 67,572 $ 49,953 $ 57,027
========== ========== ==========

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 (at September 30 for each respective year), drilling and
production activity, and financial operating data for the twelve months ended
September 30, 2002, 2001 and 2000.

GEOILBENT
--------------------------------------
YEAR ENDED SEPTEMBER 30,
--------------------------------------
2002 2001 2000
---------- ---------- ----------
(DOLLARS IN 000's)

RESERVE INFORMATION
Proved reserves (MBbls) 25,356 29,668 32,614
Discounted future net cash flow attributable to proved
reserves, before income taxes $ 117,230 $ 81,125 $ 140,160
Standardized measure of future net cash flows $ 92,939 $ 70,648 $ 114,725
DRILLING AND PRODUCTION ACTIVITY:
Gross development wells drilled 6 39 39
Net development wells drilled 2 13 13
Average daily production (Bbls) 6,438 4,830 3,945
FINANCIAL DATA:
Oil and natural gas revenues $ 31,039 $ 34,261 $ 26,716
Expenses:
Operating, selling and distribution expenses
and taxes other than on income 16,902 16,083 10,831
Depletion 9,237 5,072 3,249
Income tax expense 1,955 3,742 3,306
---------- ---------- ----------
Total expenses 28,094 24,897 17,386
---------- ---------- ----------
Results of operations from oil and natural gas
producing activities $ 2,945 $ 9,364 $ 9,330
========== ========== ==========

As of December 31, 2001 and 2000, we owned, free of any sale and
transfer restrictions, 39 and 29 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 (at September 30 for each respective year),
drilling and production activity, and financial operating data for the period
until it was sold on April 12, 2002, and twelve months ended September 30, 2001
and 2000.

5

ARCTIC GAS COMPANY
--------------------------------------
YEAR ENDED SEPTEMBER 30,
--------------------------------------
2002 2001 2000
---------- ---------- ----------
(DOLLARS IN 000's)

RESERVE INFORMATION
Proved reserves (MBOE) (a) 55,631 41,236
Discounted future net cash flow attributable to proved
reserves, before income taxes (a) $ 108,400 $ 74,517
Standardized measure of future net cash flows (a) $ 82,205 $ 56,880
DRILLING AND PRODUCTION ACTIVITY:
Gross wells reactivated (a) 2 4
Average daily production (BOE) 189 502 134
FINANCIAL DATA:
Oil and natural gas revenues $ 3,554 $ 4,016 $ 889
Expenses:
Selling and distribution expenses 1,429 1,165 --
Operating expenses and taxes other than on income 1,673 2,215 604
Depletion 139 311 78
---------- ---------- ----------
Total expenses 3,241 3,691 682
---------- ---------- ----------
Results of operations from oil and natural gas
producing activities $ 313 $ 325 $ 207
========== ========== ==========

(a) Arctic Gas was sold on April 12, 2002

SOUTH MONAGAS UNIT, VENEZUELA (BENTON-VINCCLER)

General

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

o mergers;

o consolidations;

o sales of substantially all of its corporate assets;

o change of business; and

o 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 relations 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.

6

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. Since 1992, the maximum total fee received by
Benton-Vinccler has approximated 48 percent of West Texas Intermediate crude oil
("WTI") price.

Benton-Vinccler has constructed a 25-mile oil pipeline from its oil
processing facilities at Uracoa to PDVSA's storage facility, the custody
transfer point. The operating 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. In January 2002, Benton-Vinccler installed a continuous flow
measuring unit at its facility to closely monitor the quantities of hydrocarbons
delivered to PDVSA.

At the end of each quarter, Benton-Vinccler prepares an invoice to
PDVSA based on barrels of oil accepted by PDVSA during the quarter, using
quarterly adjusted contract service fees per barrel. Payment is due under 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. While PDVSA has timely paid its past invoices, payment of the invoice
for the fourth quarter 2002 deliveries was seven days late. PDVSA indicated that
the late payment was due to business interruptions resulting from the national
civil work stoppage in Venezuela.

Natural Gas Sales Contract

On September 19, 2002, Benton-Vinccler and PDVSA signed an amendment to
the operating service agreement, providing for the delivery of up to 198 Bcf of
natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales are
expected to commence at a rate of 40 to 50 MMcf of natural gas per day in the
fourth quarter of 2003 and gradually increase up to 70 MMcfpd in 12 to 18 months
from the initial sale. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5
million barrels of oil at $7.00 per barrel beginning with our first gas sale.
Initial gas production will come from Uracoa, which allows us to more
efficiently manage the reservoir and eliminate the restrictions on producing oil
wells with high gas to oil ratios. The gas reserves in Bombal will be used to
meet the future terms of the gas contract in 2005 or 2006.

An initial capital investment of approximately $26 million will be
required to build a 64-mile pipeline with a normal capacity of 70 MMcf of
natural gas per day and a design capacity of 90 MMcf of natural gas per day, a
gas gathering system, upgrades to the UM-2 plant facilities and new gas
treatment and compression facilities. We plan to start fabrication and
construction process for the gas pipeline in early 2003. Benton-Vinccler has
borrowed $15.5 million under a project loan for the gas pipeline and related
facilities and the remainder will be funded from existing cash balances and
internally generated cash flow.

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 of the acreage. At December 31, 2002, proved reserves
attributable to our Venezuelan operations were 128,168 MBOE (102,534 MBOE net to
Harvest). This represented approximately 80 percent of our proved reserves at
year end. Benton-Vinccler has been primarily developing the Oficina sands in the
Uracoa Field. The Uracoa Field contains 62 percent of the South Monagas Unit's
proved reserves. Benton-Vinccler is currently reinjecting most of the associated
natural gas produced at Uracoa back into the reservoir.

Drilling and Development Activity

Benton-Vinccler drilled 11 oil and 2 water injection wells in 2002 and
had an average of 131 wells on production in all fields in 2002.

7

URACOA FIELD

Benton-Vinccler has been developing the South Monagas Unit since 1992,
beginning with the Uracoa Field.

Benton-Vinccler processes the oil, water and natural gas produced from
the Uracoa Field in the Uracoa central processing unit. Benton-Vinccler ships
the processed oil via pipeline to the PDVSA custody transfer point.
Benton-Vinccler treats and filters produced water, and then re-injects it into
the aquifer to assist the natural water drive. Benton-Vinccler re-injects
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 40 to 45 MMcf 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

In 2001, Benton-Vinccler reactivated nine wells in Tucupita and in 2002
completed eleven oil producers and two water injectors. The oil is transported
through a 31-mile, 20 MBbl per day capacity oil pipeline constructed in 2001
from Tucupita to the Uracoa central processing unit.

Benton-Vinccler is 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 supply our
power needs.

To date, we have drilled one well in the Bombal Field and reactivated
another.

Customers and Market Information

Under the operating service agreement, oil produced is delivered to
PDVSA for an operating fee. From December 14, 2002 through February 6, 2003, no
sales were made because of PDVSA's inability to accept our oil due to the
national civil work stoppage in Venezuela. As a result, 2002 sales were reduced
by approximately 550,000 barrels. In restoring production, we encountered
problems with some of our wells, but we do not believe the associated costs will
be material. By the end of March 2003, our average production was approximately
24,000 barrels of oil per day. While we have substantial cash reserves, a
prolonged loss of sales could have a material adverse effect on our financial
condition.

Employees and Community Relations

Benton-Vinccler has a highly skilled staff of 172 local employees and 5
expatriates and has also formed successful and supportive relationships with
local government agencies and communities.

Benton-Vinccler has invested in a Social Community Program that
includes medical programs in ophthalmologic and dental care, as well as
additional social investments including the purchase of medicines and medical
equipment in local communities within the South Monagas Unit.

Health, Safety and Environment

Benton-Vinccler's health, safety and environmental policy is an
integral part of its business. Annually, Benton-Vinccler continually improves
its policy and practices related to 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.

8

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. 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. Purneftegazgeologia and Purneftegaz (co-founding shareholders)
contributed their interest to Open Joint Stock Company Minley ("Minley") in
2001. Geoilbent's current ownership is as follows:

o Harvest -- 34 percent.

o Minley -- 66 percent.

We believe that we have developed a good relationship with Minley and
have not experienced any disagreements on major operational matters. We are
reviewing ways to improve the operations, but as a minority shareholder we may
not be able to fully effect changes in operations, if indicated as necessary or
desirable by our review. Geoilbent shareholder action requires a 67 percent
majority vote of its shareholders.

Geoilbent's oil and gas fields are situated on land belonging to the
Russian Federation. Geoilbent obtained licenses from the local authorities and
pays unified production taxes to explore and produce oil and gas from these
fields. Licenses will expire in September 2018 for the North Gubkinskoye field,
and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4
of the Russian Federal Law 20-FZ, dated January 2, 2000, the license may be
extended over the economic life of the lease at Geoilbent's option. Geoilbent
intends to extend such licenses for properties that are expected to produce
subsequent to their expiry dates. Estimates of proved reserves extending past
the license expiration currently represent approximately 5 percent of total
proved reserves.

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 proved oil and gas
fields surround all four of Geoilbent's licenses.

The North Gubkinskoye 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 Cretaceous BP 8, 9, 10, 11 and
12 reservoirs with minor development in the BP 6, 7 and Jurassic reservoirs.
Geoilbent is currently flaring the produced natural gas in accordance with
environmental regulations, although it is exploring alternatives to construct a
natural gas processing plant and to market the natural gas and natural gas
liquids.

The South Tarasovskoye Field is located southeast of North Gubkinskoye
Field and straddles the eastern boundary of the Urabor Yakhinsky exploration
block acquired by Geoilbent in 1998. It is estimated that 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.
The development to date has focused on the Cretaceous BP 7, 8, 9 and 10, and the
Jurassic reservoirs. All of the current production in South Tarasov is achieved
from the main anticlinal feature.

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

Drilling, Development, Customer and Market Information

Currently there are 109 wells in production in North Gubkinskoye and 18
in production in South Tarasovskoye. In addition, there are 37 and 2 injectors,
respectively, currently injecting water in each field.

Until Geoilbent began operations in 1992, the North Gubkinskoye Field
was one of the largest non-producing oil and gas fields in the region. Geoilbent
transports its oil production to Transneft, the state oil pipeline

9

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 handles all export oil sales, which are paid
in US dollars into Geoilbent's bank account. In 2002, approximately 34% of
Geoilbent's production was sold in the world export market and 66% in the
domestic Russian market. Geoilbent's domestic Russian crude oil price declines
significantly in the winter months. For example, during the period from
September 30, 2002 until December 31, 2002. In this same period, Russian export
prices increased from approximately $20 to $29 per barrel, however, Geoilbent's
average price declined $5.05 in value between these two periods. Geoilbent could
not export more crude oil due to Transneft and the winter export limitations.

Geoilbent is continuing to pursue its oil development program. The
current production facilities are operating at or near capacity and will need to
be expanded to accommodate future production increases. Currently gas production
from North Gubkinskoye is consumed as fuel with the remainder being flared.

In 1996, Geoilbent secured a loan from the European Bank for
Reconstruction and Development ("EBRD") to develop a portion of the oil and
condensate reserves of the North Gubkinskoye Field. The outstanding debt balance
of $22 million on the debt to EBRD has been restructured into a new $50 million
loan facility, which will be used to reduce payables and implement the South
Tarasovskoye oil development in 2003. On March 12, 2003 Geoilbent drew $8.0
million under the loan to reduce payables. However, there can be no assurance
that this draw on the credit facility will be adequate to permit Geoilbent to
meet the current financial ratio requirement under the credit facility. If
Geoilbent fails to meet the ratio requirements for two consecutive quarters it
will result in an event of default whereby EBRD may, at its option, demand
payment of the outstanding principal and interest. In addition, the restructured
loan agreement requires that Geoilbent implement a new management information
system by May 1, 2003. Geoilbent will be unable to timely satisfy this
requirement which also results in an event of default whereby EBRD may, at its
option, demand payment of the outstanding principal and interest. For a more
complete description of the terms and conditions of the EBRD loan and
Geoilbent's covenant obligations, See Item 7 - Risk Factors and Note 9 - Russian
Operations.

Employees, Community and Country Relations

Geoilbent employs six 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 resides in the area
of oilfield operations.

EAST URENGOY, RUSSIA (ARCTIC GAS COMPANY)

Arctic Gas Company was sold in April 2002. See Note 9 - Russian
Operations.

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

General

In December 1996, we acquired Crestone Energy Corporation, 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 1.25 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 another company. The
territorial dispute has lasted for many years, and there has been limited
exploration and no development activity in the area under dispute. As part of
our review of Company assets, we conducted a third-party evaluation of the
WAB-21 area. Through that evaluation and our own assessment, we recorded a $13.4
million impairment charge in the second quarter of 2002.

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.

10

Drilling and Development Activity

Due to the sovereignty issues between China and Vietnam, we have been
unable to pursue an exploration program during phase one of the contract. As a
result, we have obtained a license extension, with the current extension in
effect until May 31, 2005.

DOMESTIC OPERATIONS

We had a 35 percent working interest in the Lakeside Exploration
Prospect, Cameron Parish, Louisiana. In September 2002, we determined the Claude
Boudreaux #1 exploratory well was not prospective for hydrocarbons and assigned
our entire interest in the Lakeside Exploration Prospect to a third party and
recognized a $1.1 million impairment.

We acquired a 100 percent interest in three California State offshore
oil and gas leases ("California Leases") and a parcel of onshore property from
Molino Energy Company, LLC. All capitalized costs associated with the California
Leases have been fully impaired. The California Leases have expired and the
Company has issued the required quitclaim deed, is plugging and abandoning the
previously drilled exploratory wells and will undertake any required lease and
land reclamation. It is believed that these costs will not be material.

ACTIVITIES BY AREA

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

RESERVES

Estimates of our proved reserves as of December 31, 2002 and 2001 were
prepared by Ryder Scott Company, L.P., independent petroleum engineers. The
following table sets forth information regarding estimates of proved reserves at
December 31, 2002. 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. Russia's reserves reflect our 34 percent equity
interest in Geoilbent. Although we estimate there are substantial natural gas
reserves in the license blocks held by Geoilbent, no natural gas reserves have
been recorded as of December 31, 2002 because of a lack of sales and
transportation contracts in place.

11

Estimates of commercially recoverable oil and natural gas reserves and
of the future net cash flows derived there from are based upon a number of
variable factors and assumptions, such as:

o historical production from the subject properties;

o comparison with other producing properties;

o the assumed effects of regulation by governmental agencies; and

o assumptions concerning future operating costs, severance and excise
taxes, export tariffs, abandonment costs, development costs,
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 there from, prepared by
different engineers or by the same engineers at different times may vary
substantially. The difficulty of making precise estimates is accentuated by the
fact that 46 percent of our total proved reserves were undeveloped as of
December 31, 2002.

The following costs therefore will likely vary from our estimates and
such variances may be material:

o severance and excise taxes;

o export tariffs;

o development expenditures;

o workover and remedial expenditures;

o abandonment expenditures; and

o 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:

o actual production;

o oil sales;

o supply and demand for oil and natural gas;

o availability and capacity of gathering systems and pipelines;

o changes in governmental regulations or taxation; and

o the impact of inflation on costs.

The timing of actual future net oil and natural gas sales from proved
reserves as well as the year-end price, 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 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, risks associated with the oil and natural gas industry
and the political risks associated with operations in Venezuela and Russia.
Discounted present value, regardless of 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

12

be inaccurate. For the period ending December 31, 2002, we reported $526.7
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 operating expenses for the years ended December
31, 2002, 2001 and 2000. The presentation for Venezuela includes 100 percent of
the production, without deduction for minority interest. Geoilbent (34 percent
ownership) and Arctic Gas (39 and 29 percent ownership not subject to any sale
or transfer restrictions at December 2001 and 2000, 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, 2002, 2001 and 2000 reflect results from Geoilbent for
the twelve months ended September 30, 2002, 2001 and 2000, and from Arctic Gas
until it was sold on April 12, 2002, and for the twelve months ended September
30, 2001 and 2000.

YEAR ENDED DECEMBER 31,
-----------------------------------------
2002 2001 2000
----------- ----------- -----------

VENEZUELA
Crude Oil Production (Bbls) 9,708,295 9,777,516 9,364,088
Average Crude Oil Sales Price ($ per Bbl) $ 13.08 $ 12.52 $ 14.94
Average Operating Expenses ($ per Bbl) $ 3.26 $ 4.30 $ 5.01
GEOILBENT(a)
Net Crude Oil Production (Bbls) 2,349,916 1,762,814 1,444,181
Average Crude Oil Sales price ($ per Bbl) $ 13.21 $ 19.51 $ 18.54
Average Operating Expenses ($ per Bbl) $ 2.09 $ 2.17 $ 2.31
ARCTIC GAS (a)(b)
Net Crude Oil Production (Bbls) (b) 183,087 48,833
Average Crude Oil Sales price ($ per Bbl) (b) $ 21.93 $ 18.20
Average Operating Expenses ($ per Bbl) (b) $ 7.42 $ 5.97

(a) Information represents our ownership interest.
(b) Arctic Gas was sold on April 12, 2002.

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:

o change in governments;

o civil unrest;

o price and currency controls;

o limitations on oil and natural gas production;

o world demand for crude oil;

o tax and other laws relating to the petroleum industry;

o changes in such laws; and

o changes in administrative regulations and the interpretation and
application of such rules and regulations.

In any country in which we may do business, the oil and natural gas
industry legislation and agency regulation are 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 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.

13

Venezuela

On February 5, 2003, Venezuela imposed currency controls and created
the Commission for Administration of Foreign Currency ("CADIVI") with the task
of establishing the detailed rules and regulations and generally administering
the exchange control regime. These controls fix the exchange rate between the
Bolivar and the U.S. dollar, and restrict the ability to exchange Bolivars for
dollars and vice versa. Oil companies such as Benton-Vinccler are allowed to
receive payments for oil sales in U.S. currency and pay dollar-denominated debt,
dividends and expenses from those payments. We are unable to predict the impact
of the currency controls on us or Benton-Vinccler because the CADIVI has not
issued final regulations. The near-term effect has been to restrict
Benton-Vinccler's ability to make payments to employees and vendors in Bolivars,
causing it to borrow money on a short-term basis to meet these obligations. As
of March 14, 2003, these short-term borrowings have been repaid and while we now
have Bolivars to meet our current obligations, the situation could change. In
addition, the currency controls have increased the cost of Benton-Vinccler's
Bolivar denominated debt. We plan to prepay the Bolivar denominated debt as of
March 31, 2003.

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 budgets to PDVSA for approval including capital expenditures to
comply with Venezuelan environmental regulations. No capital expenditures to
comply with environmental regulations were required in 2002. 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 and the Ministry of Natural Resources.
Geoilbent 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 agencies, including the Ministry of
Fuel and Energy, Ministry of Natural Resources, Committee for Technical Mining
Monitoring and the State Customs Committee.

Effective in August 2001, a new tariff structure on exported oil was
instituted. The Russian government sets the maximum crude oil export tariff rate
as a percentage of the customs dollar value of Urals, Russia's main crude export
blend. Under the current system when the Urals price is in a range of $109.50 to
$182.50 per ton ($15 to $25 per Bbl) a tariff of 35 percent is imposed on the
sum exceeding the level of $109.50. When Urals crude is below $109.50 per ton no
tariff is collected. When the price rises above $182.50 per ton, exporters pay a
combined tariff comprising $25.53 per ton, plus a tariff of 40 percent on the
sum exceeding $182.50. By way of example, a $27.00 Ural price per barrel would
incur an export tariff of $4.28 per barrel. Effective January 1, 2002, mineral
restoration tax, royalty tax and excise tax on crude oil production were
abolished and replaced by the unified natural resources production tax. Through
December 31, 2004, the base rate for the unified natural resources production
tax is set at Russian Rubles 340 per metric ton of crude oil produced and is to
be adjusted on the market price of Urals blend and the Russian Ruble/US Dollar
exchange rate. The tax rate is zero if the Urals blend price falls to or below
$8.00 per barrel. From January 1, 2005, the unified natural resources production
tax rate is set by law at 16.5 percent of crude oil revenues recognized by
Geoilbent based on Regulations on Accounting and Reporting of the Russian
Federation. We are unable to predict the impact of future taxes, duties and
other burdens on Geoilbent's operations.

14

DRILLING AND UNDEVELOPED ACREAGE

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):

o $51 million during 2002;

o $44 million during 2001; and

o $50 million during 2000;

We have drilled or participated through our equity affiliate in the
drilling of wells as follows:

YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
2002 2001 2000
----------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
------ ------ ------ ------ ------ ------

WELLS DRILLED:
Exploration:
Dry hole......................... 1 0.4 -- -- -- --
Development:
Crude oil........................ 17 10.8 20 10.5 65 34.1
------ ------ ------ ------ ------ ----

Total ............................ 18 11.2 8 10.5 65 34.1
====== ====== ====== ====== ====== ======

AVERAGE DEPTH OF WELLS (FEET)............. 7,341 6,043 7,048
PRODUCING WELLS (1):
Crude Oil........................ 258 158.2 274 169.9 268 163.6

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

In 2002, Geoilbent participated in the drilling of six crude oil
wells.

All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We do not directly operate any drilling
equipment.

ACREAGE

The following table summarizes the developed and undeveloped acreage
that we owned, leased or held under operating service agreement or concession as
of December 31, 2002:

DEVELOPED UNDEVELOPED
--------------------------- --------------------------
GROSS NET GROSS NET
----------- ----------- ----------- -----------

Venezuela (Benton-Vinccler)................. 10,966 8,773 146,877 117,502
Russia (Geoilbent).......................... 36,697 12,477 1,320,146 448,850
China....................................... -- -- 7,470,080 7,470,080
----------- ----------- ----------- -----------
Total....................................... 47,663 21,250 8,937,103 8,036,432
=========== =========== =========== ===========

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 political, 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, data resources and facilities substantially greater
than ours.

15

ENVIRONMENTAL REGULATION

Various federal, state, local and international laws and regulations
relating to 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. 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 may, and
often do, 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, 2002, we had 19 full-time employees, augmented from
time-to-time with independent consultants, as required. Benton-Vinccler had 172
and Geoilbent had 700 local 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 license agreements and other 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 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
a third party. 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.

16

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.

Bbl. "Bbl" means barrel. "Bbls" means barrels. "MBbls" means thousand barrels.
"MMBbls" means million 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 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.

GAS CAP. "Gas Cap" is the natural gas trapped above the oil in a reservoir.

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.

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.

OPERATING EXPENSES. "Operating Expenses" 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 and severance taxes.

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.

17

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.

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 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 acreage contains proved
reserves.

ITEM 2. PROPERTIES

In July 2001, we leased office space in Houston, Texas for three years 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

See Note 13 - Related Party Transactions regarding the A. E. Benton proceeding.
The Company is a defendant in or otherwise involved in litigation incidental to
its business. In the opinion of management, there is no litigation which is
material to the Company.

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

None

18

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 May
20, 2002 under the symbol "HNR". Prior to that date it traded under the symbol
"BNO". As of December 31, 2002, there were 35,248,296 shares of common stock
outstanding, with approximately 866 stockholders of record. The following table
sets forth the high and low sales prices for our Common Stock reported by the
NYSE.

On March 21, 2003, the last sales price for the common stock as reported by the
NYSE was $4.40 per share.

Our policy is to retain earnings to support the growth of our business.
Accordingly, our Board of Directors has never declared a cash dividend on our
common stock and our indenture currently restricts the declaration and payment
of any cash dividends.

19

ITEM 6. SELECTED 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, 2002. 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 through our equity affiliates based on a twelve-month period
ending September 30. Accordingly, our results of operations for the years ended
December 31, 2002, 2001, 2000, 1999 and 1998 reflect results from Geoilbent for
the twelve months ended September 30, 2002, 2001, 2000, 1999 and 1998, and from
Arctic Gas (until sold on April 12, 2002) for the twelve months ended September
30, 2002, 2001, 2000, 1999 and 1998.

YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------
2002 2001 2000 1999 1998
--------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)

STATEMENT OF OPERATIONS:
Total revenues $ 126,731 $ 122,386 $ 140,284 $ 89,060 $ 82,212
Operating income (loss) 34,585 28,201 53,204 (22,525) (210,066)
Income (loss) before minority interests 109,516 42,880 23,044 (34,216) (201,413)
Net income (loss) per common share:
Basic $ 2.90 $ 1.27 $ 0.67 $ (1.09) $ (6.21)
========= ========== ========== ========== ==========
Diluted $ 2.78 $ 1.27 $ 0.66 $ (1.09) $ (6.21)
========= ========== ========== ========== ==========

Weighted average common shares outstanding
Basic 34,637 33,937 30,724 29,577 29,554
Diluted 36,130 34,008 30,890 29,577 29,554

YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------
2002 2001 2000 1999 1998
--------- ---------- ---------- ---------- ----------
(IN THOUSANDS)

BALANCE SHEET DATA:
Working capital (deficit) $ 97,001 $ (586) $ 12,370 $ 32,093 $ 60,927
Total assets 335,192 348,151 286,447 276,311 324,363
Long-term obligations, net of current
maturities 104,700 221,583 213,000 264,575 280,002
Stockholders' equity (deficit) (1) 171,317 67,623 12,904 (17,178) 12,989

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

20

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

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.

OUR CONCENTRATION OF ASSETS IN VENEZUELA INCREASES OUR EXPOSURE TO PRODUCTION
DECLINES AND DISRUPTIONS. During 2002, the production from the South Monagas
Unit in Venezuela represented all of our total production from consolidated
companies. Our production, revenue and cash flow will be adversely affected if
production from the South Monagas Unit decreases significantly for any reason.
From December 14, 2002 through February 6, 2003, no sales were made because of
PDVSA's inability to accept our oil due to the national civil work stoppage in
Venezuela. As a result, 2002 sales were reduced by approximately 550,000 barrels
and sales in 2003 were reduced by an estimated 1.2 million barrels. While the
situation has stabilized, there continues to be political and economic
uncertainty that could lead to another disruption of our sales. In restoring
production, we encountered problems with some wells, but we do not believe the
associated costs will be material. By the end of March 2003, our average
production was approximately 24,000 barrels of oil per day. As a result of the
national civil work stoppage, the Government of Venezuela terminated several
thousand PDVSA employees and announced a decentralization of PDVSA's operations.
While the effect of these changes cannot be predicted, it could adversely affect
PDVSA's ability to manage its contracts and meet its obligations with its
suppliers and vendors, such as Benton-Vinccler. As a result of the situation in
PDVSA, its payment to Benton-Vinccler for crude delivered in the fourth quarter
2002 was late by seven days. We believe that the payment demonstrates PDVSA's
commitment to building its production levels back to full capacity and returning
to more normalized business relations with its customers and suppliers. While we
have substantial cash reserves to withstand a future disruption, a prolonged
loss of sales or a failure or delay by PDVSA to pay our invoices could have a
material adverse effect on our financial condition. We have been required to
curtail sales to PDVSA in April and December 2002 due to insufficient crude oil
storage capacity. We have never been required to curtail sales before 2002. We
cannot be assured that our sales to PDVSA will not be curtailed in the future in
the same manner.

GEOILBENT'S LIQUIDITY COULD LIMIT ITS ABILITY TO MAINTAIN OR INCREASE
PRODUCTION.

ABILITY TO COMPLY WITH CREDIT FACILITY. The $50 million revolving credit
agreement with EBRD requires that Geoilbent meet certain covenants which
include, among other things, the maintenance of financial ratios. If Geoilbent
fails to meet the ratio requirements for two consecutive quarters it will result
in an event of default whereby EBRD may, at its option, demand payment of the
outstanding principal and interest. In addition, the loan agreement requires
that Geoilbent implement a new management information system by May 1, 2003. If
Geoilbent is unable to timely satisfy this requirement, it also results in an
event of default whereby EBRD may, at its option, demand payment of the
outstanding principal and interest. Any event of default also gives EBRD the
right to exercise its security interest in the assets of Geoilbent and, under a
share pledge agreement, our ownership interest in Geoilbent. An event of default
could also limit Geoilbent's ability to access additional funds under the EBRD
facility. It is unlikely that Geoilbent will be able to timely implement a new
management information system as required by the EBRD loan facility. Further,
while on March 12, 2003, Geoilbent has drawn down $8 million on the EBRD
facility to meet its current liabilities, there can be no assurance that
Geoilbent will be able to meet the current ratio requirement on March 31, 2003.
As a result of these events Geoilbent's independent accountants have indicated
in their report that substantial doubt exists regarding Geoilbent's ability to
meet its debts as they come due and continue as a going concern. While no
assurance can be given, the Company believes these covenant defaults are
temporary and does not result in an other than temporary decline in the
Company's investment in Geoilbent or will cause EBRD to declare a default after
considering Geoilbent's historical net income, cash flow from operating
activities and other matters.

ABILITY TO REPAY ACCOUNTS PAYABLE. At September 30, 2002, and September 30,
2001, the current liabilities of Geoilbent exceeded its current assets by $35.3
million and $25.0 million, respectively. Included in current liabilities as of
September 30, 2002 are loans repayable to EBRD ($22.0 million) and IMB ($0.6
million). The IMB liability was repaid in November 2002. This debt has been
classified as current because of Geoilbent's status under the

21

EBRD loan. At December 31, 2002, Geoilbent had accounts payable outstanding of
$12.2 million of which approximately $5.9 million was 90 days or more past due.
The amounts outstanding were primarily to contractors and vendors for drilling
and construction services. Under Russian law, creditors, to whom payments are 90
days or more past due, can force a company into involuntary bankruptcy. We
believe most of the significantly overdue payables have now been paid as a
result of the $8 million draw down of the EBRD facility.

ABILITY TO REPAY OUR LOAN. As of September 30, 2002, the Geoilbent shareholders
had provided Geoilbent with subordinated loans totaling $7.5 million ($2.5
million from Harvest and $5.0 million from Minley). These loans are unsecured
and repayable commencing in January 2004. Our interest rate is based on LIBOR up
to January 2004, and rises from 8 to 12 percent thereafter. There can be no
assurance that Geoilbent will have the ability to repay the loan made by the
Company when due.

ABILITY TO MAINTAIN OR INCREASE PRODUCTION. Because of Geoilbent's significant
working capital deficit, a substantial portion of its cash flow must be utilized
to reduce accounts and taxes payable. Additionally, in order to maintain or
increase proved oil and gas reserves, Geoilbent must make substantial capital
expenditures in 2003. Geoilbent's net cash provided by operating activities is
dependent on the level of oil prices, which are historically volatile and are
significantly impacted by the proportion of production that Geoilbent can sell
on the export market. Historically, Geoilbent has supplemented its cash flow
from operations with additional borrowings or equity capital. Should oil prices
decline for a prolonged period, or if Geoilbent is unable to access the EBRD
facility or the shareholders are unwilling to make capital contributions, then
Geoilbent would need to reduce its capital expenditures, which could limit its
ability to maintain or increase production and, in turn, meet its debt service
requirements. Although the Company may consider making a capital contribution,
there can be no assurances that the Company will do so, nor can there be any
assurances that Geoilbent's other shareholder will be willing or able to do so.
Asset sales and financing are restricted under the terms of the EBRD loan.

OUR MINORITY INTEREST IN GEOILBENT MAY LIMIT OUR ABILITY TO INFLUENCE CHANGE. We
own 34 percent in Geoilbent. We are reviewing ways to improve operations, such
as the secondment of expatriate employees or consultants, the upgrading of
drilling equipment, improved operating techniques and economic decision making,
but we are a minority partner and therefore may not be able to fully influence
changes in the operations.

OUR OPERATIONS IN AREAS OUTSIDE THE U.S. ARE SUBJECT TO VARIOUS RISKS INHERENT
IN FOREIGN OPERATIONS, AND OUR STRATEGY TO FOCUS ON VENEZUELA AND RUSSIA LIMITS
OUR COUNTRY RISK DIVERSIFICATION. Our 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, civil unrest, strikes 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 our international operations. Our international
operations may also be adversely affected by laws and policies of the United
States affecting foreign trade, taxation and the possibility of having to be
subject to exclusive jurisdiction of courts in connection with legal disputes
and the possible inability to subject foreign persons to the jurisdiction of the
courts in the United States. Our strategy to focus on Venezuela and Russia
concentrates our foreign operations risk and increases the potential impact to
us of the operating, financial and political risks in those countries.

OUR FOREIGN OPERATIONS EXPOSE US TO FOREIGN CURRENCY RISK. Our principal
operations are in Venezuela and Russia which have historically been considered
highly inflationary economies. Results of operations in those countries are
re-measured in United States dollars, and all currency gains or losses are
recorded in the consolidated statement of operations. There are many factors
which affect foreign exchange rates and resulting exchange gains and losses,
many of which are beyond our influence. We have 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 we may be affected by future changes in
exchange rates. Our Venezuelan receipts are denominated in U.S. dollars, and
most expenditures are in U.S. dollars as well. For a discussion of currency
controls in Venezuela, see CAPITAL RESOURCES AND LIQUIDITY below.

22

NEW YORK STOCK EXCHANGE DELISTING. In October 2001, we received a letter from
the New York Stock Exchange ("NYSE") notifying us that we had fallen below the
continued listing standard of the NYSE. These standards include a total market
capitalization of at least $50 million over a 30-day trading period and
stockholders' equity of at least $50 million. According to the NYSE's notice,
our total market capitalization over the 30 trading days ended October 17, 2001
was $48.2 million and our stockholders' equity was $16.0 million as of September
30, 2001. In accordance with the NYSE's rules, we submitted a plan to the NYSE
detailing how we expected to reestablish compliance with the listing criteria
within the next 18 months. In January 2002, the NYSE accepted our business plan,
subject to quarterly reviews of the goals and objectives outlined in that plan.
By April 2002, the total market capitalization and stockholder's equity
deficiencies were eliminated, and as of December 31, 2002, we remained in
compliance with NYSE listing standards.

LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS. As of December 31, 2002, our
long-term debt was $104.7 million. Our long-term debt represented 38 percent of
our debt to total capital at December 31, 2002. Our current cash balances lessen
the impact of our debt but it can effect our operations in several important
ways, including the following:

o a significant portion of our cash flow from operations is used to
pay interest on borrowings;

o the covenants contained in the indentures governing our debt limit
our ability to borrow additional funds or to dispose of assets;

o the covenants contained in the indentures governing our debt affect
our flexibility in planning for, and reacting to, changes in
business conditions;

o the level of debt could impair our 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 our debt permit our creditors
to accelerate payments upon an event of default or a change of
control.

OIL PRICE DECLINES AND VOLATILITY COULD ADVERSELY AFFECT OUR REVENUE, CASH FLOWS
AND PROFITABILITY. Prices for oil fluctuate widely. The average price we
received for oil in Venezuela increased to $13.08 per Bbl for the year ended
December 31, 2002, compared to $12.52 per Bbl for the year ended December 31,
2001. Our 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 we can produce economically. We 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; and

o overall economic conditions.

LOWER OIL AND NATURAL GAS PRICES MAY CAUSE US TO RECORD CEILING LIMITATION
WRITEDOWNS. We use the full cost method of accounting to report our oil and
natural gas operations. Accordingly, we capitalize 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 percent, 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, we must charge the amount of the excess to earnings.
This is called a "ceiling limitation write-down". This charge does not impact
cash flow from operating activities, but does reduce stockholders' equity. The
risk that we will be required to write down the carrying value of our oil and
gas properties increases when oil and natural gas prices are low or volatile. In
addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves. No ceiling test write-downs were
required in 2002.

23

ESTIMATES OF OIL AND NATURAL GAS RESERVES ARE UNCERTAIN AND INHERENTLY
IMPRECISE. This Form 10-K contains estimates of our proved oil and natural gas
reserves and the estimated future net revenues from such reserves. These
estimates are based upon various assumptions, including assumptions required by
the Securities and Exchange Commission relating to oil and natural gas prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds.

The process of estimating oil and natural 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 natural gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and natural
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, we may adjust estimates of proved reserves to
reflect production history, results of exploration and development, prevailing
oil and natural gas prices and other factors, many of which are beyond our
control. Actual production, revenue, taxes, development expenditures and
operating expenses with respect to our reserves will likely vary from the
estimates used. Such variances may be material.

At December 31, 2002, approximately 46 percent of our 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 our future
reserves include the assumption that we will make significant capital
expenditures to develop these reserves. Although we have prepared estimates of
our oil and natural gas reserves and the costs associated with these reserves in
accordance with industry standards, we 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 Natural Gas
Producing Activities.

You should not assume that the present value of future net revenues
referred to is the current market value of our estimated oil and natural 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 demand, our ability to
produce, 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 percent 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 our risks or
the risks associated with the oil and natural gas industry in general will
affect the accuracy of the 10 percent discount factor.

WE 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. Our reserves
will decline as they are produced unless we acquire properties with proved
reserves or conduct successful exploration and development activities. Our
future oil production is highly dependent upon our level of success in finding
or acquiring additional reserves. The business of exploring for, developing or
acquiring reserves is capital intensive and uncertain. We may be unable to make
the necessary capital investment to maintain or expand our oil and natural gas
reserves if cash flow from operations is reduced and external sources of capital
become limited or unavailable. We cannot assure you that our future exploration,
development and acquisition activities will result in additional proved reserves
or that we will be able to drill productive wells at acceptable costs.

OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND NATURAL GAS DRILLING AND
PRODUCTION ACTIVITIES. Oil and natural 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 natural gas drilling and production
activities may be shortened, delayed or canceled as a result of a variety of
factors, many of which are beyond our control. These factors include:

24

o unexpected drilling conditions;

o pressure or irregularities in formations;

o equipment failures or accidents;

o weather conditions;

o shortages in experienced labor;

o shortages or delays in the delivery of equipment; and

o delays in receipt of permits or access to lands.

The prevailing price of oil also affects the cost of and the demand for
drilling rigs, production equipment and related services. We cannot assure you
that the new wells we drill will be productive or that we will recover all or
any portion of our 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 NATURAL GAS INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS. The oil
and natural 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, natural gas leaks, pipeline ruptures or discharges of toxic
gases. If any of these industry operating risks occur, we 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, we maintain insurance against some, but not all, of the risks
described above. The events of September 11, 2001 forced changes to our
insurance coverage. Acts of terrorism are "excluded risks" from our property
insurance coverage. We cannot assure you that our insurance will be adequate to
cover losses or liabilities. We cannot predict the continued availability of
insurance at premium levels that justify its purchase.

COMPETITION WITHIN THE INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS. We operate
in a highly competitive environment. We compete with major and independent oil
and natural 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 ours.

OUR OIL AND NATURAL GAS OPERATIONS ARE SUBJECT TO VARIOUS GOVERNMENTAL
REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS. Our oil and natural gas
operations are subject to various foreign governmental regulations. These
regulations may be changed in response to economic or political conditions.
Matters regulated may 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 or limit supplies of oil and natural gas, these
agencies have restricted the rates of flow of oil and natural gas wells below
actual production capacity. We cannot predict the ultimate cost of compliance
with these requirements or their effect on our operations.

2002 FINANCIAL AND OPERATIONAL PERFORMANCE

We had two overriding strategic priorities for 2002: (i) to reduce the
amount of debt on the balance sheet; and (ii) to improve the value of our
producing assets. We also strengthened our management team and recommitted, as a
management team and board of directors, to maintain the highest standards in
corporate governance, financial transparency and business ethics. In May 2002,
the shareholders approved our name change to Harvest Natural Resources, Inc. In
September 2002, our board of directors authorized the repurchase of up to one
million shares of our common stock. As of March 11, 2003, we have repurchased
approximately 80,000 shares for an aggregate price of $0.4 million.

The balance sheet was significantly strengthened by completing the sale
of Arctic Gas which produced $220 million in cash and net proceeds, after taxes
and expenses, of $190 million (including $30 million for repayment of our
intercompany debt) and were used, in part, to redeem all of the $108 million of
11.625 percent senior notes due in May 2003. An additional $20 million of the
$105 million of 9.375 percent senior notes due in November 2007 were also
retired. The balance of the proceeds were retained to improve our financial
flexibility and to be available

25

for acquisitions, reduction of debt or other general corporate purposes. This
strategy has already been partially rewarded by our ability to maintain our
financial flexibility in spite of the loss of production temporarily as a result
of the national civil work stoppage in Venezuela. At December 31, 2002, we had
$91.9 million of cash or marketable securities and a debt to total capital ratio
of 38 percent compared with over 77 percent at the end of 2001.

We also improved the value of our production, an equally important
second priority. We have lowered the cash costs (lease operating, general and
administrative) of our produced barrel by 19 percent year-on-year to
approximately $5.20 per barrel, increasing unit profitability. We also
successfully negotiated a contract to sell 198 Bcf of natural gas to PDVSA over
the next 10 years. Establishing a market for this gas allowed us to record an
additional 26 net MMBOE of reserves in 2002.

In 2002, Geoilbent, in which we have a 34% interest, was able to
improve production. Geoilbent increased production by 33 percent to 7 million
barrels per year and has begun restructuring its balance sheet, by converting
the loan with EBRD into a $50 million revolving line of credit. Subject to
availability, this credit facility will allow Geoilbent to reduce its current
liabilities and accelerate the development of the South Tarasovskoye oil field
in western Siberia. However, as discussed above under Geoilbent Liquidity,
significant issues exist over Geoilbent continuing as a going concern.

2003 CAPITAL PROGRAM

Benton-Vinccler's capital expenditures for 2003 are projected to be $45
to $50 million, compared with 2002 capital expenditures of $43 million. To
partially fund its capital program, Benton-Vinccler borrowed $15.5 million in
October 2002 for the construction of the pipeline and related facilities to
deliver gas to PDVSA. Benton-Vinccler has also hedged a portion of its 2003 oil
production by purchasing a WTI crude oil "put" to protect part of its 2003 cash
flow.

In January 2003, we completed our Tucupita Field development program
in Venezuela. In 2003, Benton-Vinccler plans to drill three oil wells in the
Bombal Field and construct a pipeline from Bombal to the Tucupita delivery line.
Benton-Vinccler also plans to convert two gas injection wells in Uracoa to gas
production. Other capital projects relate to the gas project and facilities
improvements.

Geoilbent's capital expenditures for 2003 are projected to be
approximately $20 million. In 2003, Geoilbent plans to drill up to eighteen
wells in South Tarasovskoye and to commence a comprehensive work over program in
North Gubkinskoye. An appraisal well is planned in 2003 to delineate a potential
south extension of the South Tarasovskoye field that will be developed with
further drilling if successful. Geoilbent expects to fund the South Tarasovskoye
drilling program through draw downs from the EBRD loan facility. For a
description of the EBRD loan agreement and a discussion of Geoilbent's
compliance with the covenants and possible liquidity problems, see Geoilbent's
Liquidity above and Note 9 - Russian Operations.

RESULTS OF OPERATIONS

We include the results of operations of Benton-Vinccler in our
consolidated financial statements and reflect the 20 percent ownership interest
of Vinccler as a minority interest. We account for our investments in Geoilbent
and Arctic Gas using the equity method. We include Geoilbent and Arctic Gas in
our consolidated financial statements based on a fiscal year ending September
30. Our results of operations for the year ended December 31, 2002, reflect the
results of Geoilbent and Arctic Gas (until sold on April 12, 2002) for the
twelve months ended September 30, 2002, 2001 and 2000.

You should read the following discussion of the results of operations
for each of the years in the three-year period ended December 31, 2002 and the
financial condition as of December 31, 2002 and 2001 in conjunction with our
Consolidated Financial Statements and related Notes thereto.

26

We have presented selected expense items from our consolidated income
statement as a percentage of crude oil sales in the following table:

YEARS ENDED DECEMBER 31, 2002 AND 2001

Net income for the year ended December 31, 2002 was $100.4 million, or
$2.78 per diluted share, compared with $43.2 million for the same period last
year. The $100.4 million net income included the after-tax gain from the Arctic
Gas Sale of $93.6 million, and the pre-tax $3.3 million, partial recovery of a
bad debt related to A. E. Benton (See Note 13 - Related Party Transactions);
offset, in part, by a pre-tax $13.4 million impairment of the WAB-21 petroleum
property located in the South China Sea. Operating and general and
administrative expenses were reduced by $12 million, or almost 20 percent
compared with 2001.

Our results of operations for the year ended December 31, 2002
primarily reflected the results for Benton-Vinccler in Venezuela, which
accounted for all of our production and oil sales revenue. As a result of
increases in world crude oil prices, partially offset by lower production from
the South Monagas Unit, oil sales in Venezuela were 3.8 percent higher in 2002
compared with 2001. Realized fees per barrel increased 4.5 percent (from $12.52
in 2001 to $13.08 in 2002).

Our revenues increased $4.6 million, or 3.6 percent, during the year
ended December 31, 2002, compared with 2001. This was due to increased oil sales
revenue in Venezuela as a result of increases in world crude oil prices,
partially offset by lower sales quantities. Our sales quantities for the year
ended December 31, 2002 from Venezuela were 9.7 MMBbls compared to 9.8 MMBbls
for the year ended December 31, 2001. The decrease in sales quantities of
100,000 Bbls, or less than 1 percent, was due primarily to logistics and
equipment delays in early 2002 at the Tucupita field and the national civil work
stoppage which led to the shut-in of our production in late December 2002 for
nine days. Average production for the year decreased by less than 775 Bbls per
day for the aforementioned reasons.

Our operating expenses decreased $8.8 million, or 21 percent, for the
year ended December 31, 2002, compared with the year ended December 31, 2001.
Lower fuel gas, water and oil treatments accounted for $3.4 million of the
reduction. Reduced workover expense ($2.6 million) and lower expenses associated
with the transportation of Tucupita oil ($5.0 million) with the completion of
the Tucupita oil pipeline in late 2001 were offset by $1.1 million of increases
in various other categories. Depletion, depreciation and amortization increased
$0.8 million, or 4 percent, during the year ended December 31, 2002, compared
with 2001 primarily due to the first three quarters of 2002 having been
calculated on the lower beginning of the year reserves. We added 198 Bcf or 33
MMBOE in the fourth quarter which will impact this calculation prospectively.
Depletion expense per barrel of oil produced from Venezuela during 2002 was
$2.57 compared with $2.26 during 2001 primarily due to future development costs.
We recognized write-downs of capitalized costs of $13.4 million associated with
WAB-21 offshore China and $1.1 million for the Lakeside Prospect exploration
activities during the year ended December 31, 2002, compared with $0.5 million
associated with final costs associated with prior exploration activities.
General and administrative expenses decreased $3.6 million from 2001 to 2002.
The move to Houston was completed in 2001 and overall staff levels were reduced
to the current level of ten in Houston. We recognized $3.3 million of income for
the partial recovery of prior year bad debt allowance for the funds received
from the A.E. Benton bankruptcy. The consideration includes 600,000 shares of
stock taken into treasury at a price of $3.56 per share and approximately $1.1
million in cash.

Taxes other than on income decreased $1.3 million, or 24 percent,
during the year ended December 31, 2002, compared with 2001. This was primarily
due to decreased Venezuelan municipal taxes and a one-time adjustment of U.S.
employment taxes of $0.7 million.

27

Investment income and other decreased $1.0 million, or 33 percent,
during the year ended December 31, 2002, compared with 2001. This was due to
lower interest rates earned on average cash and marketable securities balances.
Interest expense decreased $8.6 million, or 34 percent, during the year ended
December 31, 2002, compared with 2001. We redeemed all $105 million of our
11.625 percent Senior Notes due in May 2003 and purchased $20 million face of
the 9.375 percent Senior Notes due in November 2007. In October 2002, we
borrowed under a $15.5 million loan to finance the construction of the gas
pipeline in Venezuela from the Uracoa field to the PDVSA sales line.

Net gain on exchange rates increased $3.8 million, or 493 percent for
the year ended December 31, 2002, compared with 2001. This was due to the
significant devaluation of the Bolivar. We realized income before income taxes
and minority interest of $169.8 million during the year ended December 31, 2002,
compared with $7.2 million in 2001. The increase was dominated by the Arctic Gas
Sale. The 2001 income tax benefit related to the potential utilization by the
Arctic Gas Sale of net operating loss carry forwards in 2002. The effective tax
rate of 36 percent reflects the approximate rate for Venezuela and no tax
benefits are being recognized for expenses incurred in the U.S. The income
attributable to the minority interest increased $3.8 million for the year ended
December 31, 2002, compared with 2001. This was primarily due to the increased
profitability (oil prices) and reduced expenses of Benton-Vinccler.

Equity in net earnings of affiliated companies decreased $5.7 million,
during the year ended December 31, 2002, compared with 2001. This was primarily
due to the decreased income from Geoilbent and the elimination of Arctic Gas
equity income on April 12, 2002, the date of its sale. Geoilbent's equity income
declined from $7.0 million in 2001 to $1.6 million in 2002. We recorded equity
in net losses of Arctic Gas in both years. Revenues from Geoilbent were $31.0
million for the year ended September 30, 2002, compared with $34.4 million for
2001. The decrease of $3.3 million, or 10 percent, was due to lower Russian
domestic crude oil prices offset by higher sales quantities. Prices for
Geoilbent's export crude oil averaged $21.73 per Bbl and its domestic crude oil
averaged $8.89 during the year ended September 30, 2002, compared with $20.48
per Bbl for export crude oil and $13.69 for domestic for the year ended
September 30, 2001. Our share of Geoilbent oil sales quantities increased by
587,102 Bbls, or 33 percent, from 1,762,814 Bbls sold during the year ended
September 30, 2001, to 2,349,916 Bbls sold during the year ended September 30,
2002.

YEARS ENDED DECEMBER 31, 2001 AND 2000

Our results of operations for the year ended December 31, 2001
primarily reflected the reversal of our tax valuation allowance and results for
Benton-Vinccler in Venezuela, which accounted for all of our production and oil
sales revenue. As a result of decreases in world crude oil prices, partially
offset by higher production from the South Monagas Unit, oil sales in Venezuela
were 13 percent lower in 2001 compared with 2000. Realized fees per barrel
decreased 16 percent (from $14.94 in 2000 to $12.52 in 2001) and oil sales
quantities increased 4 percent (from 9.4 MMBbls of oil in 2000 to 9.8 MMBbls of
oil in 2001). Our operating expenses from the South Monagas Unit decreased by 14
percent due to decreased workover costs and completion of the 31-mile oil
pipeline in the fourth quarter of 2001 to transport oil from the Tucupita field
to the central processing unit in the Uracoa field.

Our revenues decreased $17.9 million, or 13 percent, during the year
ended December 31, 2001 compared with 2000. This was due to decreased oil sales
revenue in Venezuela as a result of decreases in world crude oil prices,
partially offset by higher sales quantities. Our sales quantities for the year
ended December 31, 2001 from Venezuela were 9.8 MMBbls compared to 9.4 MMBbls
for the year ended December 31, 2000. The increase in sales quantities of
413,428 Bbls, or 4 percent, was due primarily to production efficiency and
reservoir management at Uracoa, and enhanced drilling performance for the eight
wells drilled in the Uracoa field beginning August 31, 2001 as a result of
incorporating information from the field simulation study conducted during the
first eight months of 2001. Production increased to 28,000 Bbls or oil per day
by the end of 2001 as a result of drilling 8 additional wells during the year.
Prices for crude oil averaged $12.52 per Bbl (pursuant to terms of an operating
service agreement) from Venezuela compared with $14.94 per Bbl for 2000.

Our operating expenses decreased $4.7 million, or 10 percent, which
included a fuel gas charge of $3.2 million, during the year ended December 31,
2001 compared to the year ended December 31, 2000. The fuel gas charge related
to a dispute regarding a difference between rates we paid and rates claimed by
PDVSA for natural gas used as fuel for the period 1997 through 2000. Depletion,
depreciation and amortization increased $8.3 million, or 48 percent, during the
year ended December 31, 2001 compared with 2000 primarily due to decreased
proved reserves. Depletion expense per barrel of oil produced from Venezuela
during 2001 was $2.26 compared with $1.68 during 2000 as a result of a

28

decrease in proved reserves. We recognized write-downs of capitalized costs of
$0.5 million associated with exploration activities during the year ended
December 31, 2001 compared with $1.3 million associated with exploration
activities in California. General and administrative expenses decreased $2.3
million from $16.7 million in 2000 to $14.4 million in 2001, exclusive of $5.7
million of non-recurring costs. Non-recurring general and administrative costs
are comprised of $2.3 million in debt exchange cost, $1.1 million in California
lease relinquishment, $0.2 million relocation costs to Houston and $2.1 million
severance and termination payments paid or accrued in 2001.

Taxes other than on income increased $1.0 million, or 22 percent,
during the year ended December 31, 2001 compared with 2000. This was primarily
due to increased Venezuelan municipal taxes.

Investment income and other decreased $5.5 million, or 64 percent,
during the year ended December 31, 2001 compared with 2000. This was due to
lower average cash and marketable securities balances. Interest expense
decreased $4.1 million, or 14 percent, during the year ended December 31, 2001
compared with 2000. This was primarily due to the reduction of debt balances,
partially offset by a reduction of capitalized interest expense. Net gain on
exchange rates increased $0.4 million, or 136 percent for the year ended
December 31, 2001 compared with 2000. This was due to changes in the value of
the Bolivar. We realized income before income taxes and minority interest of
$7.2 million during the year ended December 31, 2001 compared with $33.1 million
in 2000. The negative effective tax rate varies from the U.S. statutory rate of
35 percent primarily because of the reversal of a U.S. tax valuation allowance.
The reversal related to the potential utilization of net operating loss carry
forwards. We have determined that it is more likely than not that these U.S.
deferred tax assets will be realized in 2002. The income attributable to the
minority interest decreased $2.3 million for the year ended December 31, 2001
compared with 2000. This was primarily due to the decreased profitability (oil
prices) of Benton-Vinccler.

Equity in net earnings of affiliated companies increased $0.6 million,
or 11 percent, during the year ended December 31, 2001 compared with 2000. This
was primarily due to the increased income from Geoilbent. Our share of revenues
from Geoilbent was $34.4 million for the year ended September 30, 2001 compared
with revenues of $26.8 million for 2000. The increase of $7.6 million, or 27
percent, was due to higher world crude oil prices and higher sales quantities.
Prices for Geoilbent's crude oil averaged $19.51 per Bbl during the year ended
September 30, 2001 compared with $18.54 per Bbl for the year ended September 30,
2000. Our share of Geoilbent oil sales quantities increased by 318,633 Bbls, or
22 percent, from 1,444,181 Bbls sold during the year ended September 30, 2000 to
1,762,814 Bbls sold during the year ended September 30, 2001.

CAPITAL RESOURCES AND LIQUIDITY

The oil and natural gas industry is a highly capital intensive and
cyclical business with unique operating and financial risks (see Risk Factors).
We require capital principally to service our debt and to fund the following
costs:

o drilling and completion costs of wells and the cost of production,
treating and transportation facilities;

o geological, geophysical and seismic costs; and

o acquisition of interests in oil and gas properties.

The amount of available capital will affect the scope of our operations
and the rate of our growth. Our future rate of growth also depends 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 2002,
Benton-Vinccler instituted a hedging program to establish a crude oil price
floor using a WTI costless collar for our Tucupita development drilling program.
Benton-Vinccler has also hedged a portion of its 2003 oil sales by purchasing a
WTI crude oil "put" to protect its 2003 cash flow. The put is for 10,000 barrels
of oil per day for the period of March 1, 2003 through December 31, 2003. Due to
the pricing structure for our Venezuela oil, the put has the economic effect of
hedging approximately 20,000 Bopd. The put costing $2.50 per barrel, or
approximately $7.7 million, has a strike price of $30.00 per barrel.

In February 2002, the Venezuelan Bolivar was allowed to float against
the U.S. dollar. On February 5, 2003, the Venezuelan government imposed currency
controls and created the Commission for Administration of Foreign Currency
("CADIVI") with the task of establishing the detailed rules and regulations and
generally administering the exchange control regime. The currency controls fix
the exchange rate between the Bolivar and the U.S. dollar, and restricts the
ability to exchange Bolivars for dollars and vice versa. Oil companies, such as
Benton-Vinccler are allowed to receive payments for oil sales in U.S. currency
and pay dollar-denominated expenses from those payments. We are

29

unable to predict the full impact of the currency controls on us or
Benton-Vinccler as the CADIVI has not issued final regulations. The near-term
effect has been to restrict Benton-Vinccler's ability to make payments to
employees and vendors in Bolivars, causing it to borrow money on a short-term
basis to meet these obligations. All of these short-term borrowings have been
repaid and while we now have Bolivars to meet our current obligations, the
situation could change. In addition, the currency controls have increased the
cost of Benton-Vinccler's Bolivar denominated debt. Benton-Vinccler has provided
the thirty day notice of its intention to repay its Bolivar denominated debt.
The full amount will be repaid on March 31, 2003. As of February 24, 2003, we
have cash reserves of approximately $75 million and do not expect the currency
conversion restriction to adversely affect our ability to meet our short-term
loan obligations.

Our ability to pay interest on our debt and general corporate overhead
is dependent upon the ability of Benton-Vinccler to make loan repayments,
dividends and other cash payments to us. However, there have been, and may again
be, unforeseeable interruptions in oil and gas sales or there may be contractual
obligations or legal impediments such as the recently instituted currency
controls to receiving dividends or distributions from Benton-Vinccler, which
could prohibit Benton-Vinccler from remitting funds to us. Management does not
believe that the currency controls will prohibit our ability to receive funds
from Benton-Vinccler, although were it to do so, our ability to meet our cash
requirements would be adversely affected.

Debt Reduction. We currently have a significant debt principal obligation
payable in 2007 ($85 million). We intend to continue to evaluate open market
debt purchases of the obligations due in 2007 to further reduce debt. In 2001
Benton-Vinccler borrowed $12.3 million from a Venezuelan commercial bank for the
construction of a Tucupita to Uracoa oil pipeline. Benton-Vinccler has provided
the thirty day notice of its intention to repay its Bolivar denominated debt.
The full amount will be repaid on March 31, 2003. As of February 24, 2003, we
have cash reserves of approximately $75 million and do not expect the currency
conversion restriction to adversely affect our ability to meet our short-term
loan obligations.

Working Capital. Our capital resources and liquidity are affected by the timing
of our semiannual interest payments of approximately $4.0 million each May 1 and
November 1 on the 9.375 percent Senior Notes due in November 2007 and by receipt
of the quarterly payments from PDVSA at the end of the months of February, May,
August and November pursuant to the terms of the contract between
Benton-Vinccler and PDVSA regarding the South Monagas Unit. As a consequence of
the timing of these interest payment outflows and the PDVSA payment inflows, our
cash balances can increase and decrease dramatically on a few dates during the
year. In each May and November in particular, interest payments at the beginning
of the month and PDVSA payments at the end of the month create large swings in
our cash balances. At December 31, 2002, we had $91.9 million of cash or cash
equivalents.

Benton-Vinccler's oil and gas pipeline project loans allow the lender
to accelerate repayment if production ceases for a period greater than thirty
days. During the production shut-in which started in December 2002,
Benton-Vinccler was granted a waiver of this provision until February 18, 2003
for a prepayment of the next two principal obligations aggregating $0.9 million.
This prepayment, while using cash reserves, reduces our net interest expense as
the current interest expense was more than the current interest income earned on
the invested funds. On February 8, 2003, Benton-Vinccler commenced production,
thereby eliminating the need for an additional waiver. A future disruption of
production could trigger the debt acceleration provision again. While no
assurances can be given, we believe Benton-Vinccler would be able to obtain
another waiver.

The net funds raised and/or used in each of the operating, investing
and financing activities are summarized in the following table and discussed in
further detail below:

YEAR ENDED DECEMBER 31,
-------------------------------------------
(IN THOUSANDS)
2002 2001 2000
---------- ---------- ----------

Net cash provided by operating activities............ $ 42,627 $ 36,608 $ 51,763
Net cash provided by (used in) investing activities.. 126,492 (48,012) (28,772)
Net cash provided by (used in) financing activities.. (113,642) 5,296 (29,006)
---------- ---------- ----------
Net increase (decrease) in cash...................... $ 55,477 $ (6,108) $ (6,015)
========== ========== ==========

30

At December 31, 2002, we had current assets of $132.0 million and
current liabilities of $35.0 million, resulting in working capital of $97.0
million and a current ratio of 3.8:1. This compares with a negative working
capital of $0.6 million and a negative current ratio at December 31, 2001. The
increase in working capital of $97.6 million was primarily due to higher oil
prices and the Arctic Gas Sale.

Cash Flow from Operating Activities. During the years ended December
31, 2002 and 2001, net cash provided by operating activities was approximately
$42.6 million and $36.6 million, respectively. The $6.0 million increase was
primarily due to higher oil revenues and lower operating expenses.

Cash Flow from Investing Activities. During the year ended December
31, 2002 and 2001, we had drilling and production-related capital expenditures
of approximately $43.3 million and $43.4 million, respectively. Of the 2002
expenditures, $42.5 million was attributable to the development of the South
Monagas Unit and $0.8 million was attributable to Lakeside Exploration Prospect.

The timing and size of capital expenditures for the South Monagas Unit
are entirely at our discretion. We anticipate that Geoilbent will continue to
fund its expenditures through its own cash flow and credit facilities. Our
remaining capital commitments worldwide are relatively minimal and are
substantially at our discretion. We will also be required to make annual
interest payments of approximately $8.0 million on the 2007 Notes.

We continue to assess production levels and commodity prices in
conjunction with our capital resources and liquidity requirements.
Benton-Vinccler entered into a commodity contract (costless collar) in 2002 and,
as described above, a WTI crude oil "put" for a portion of 2003.

Cash Flow from Financing Activities. In November 1997, we issued $115
million in 9.375 percent senior unsecured notes due November 1, 2007, of which
we subsequently repurchased $30 million at their par value for cash. Interest on
these 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, 2002, we were in compliance with all covenants of the
indenture.

We have an approximately $11,000 lease obligation per month for our
Houston office space. This lease is valid through August 2004. The following
table summarizes our contractual obligations at December 31, 2002.

PAYMENTS (IN THOUSANDS) DUE BY PERIOD
-------------------------------------------------------------------------
LESS THAN AFTER 4
CONTRACTUAL OBLIGATION TOTAL 1 YEAR 1-2 YEARS 3-4 YEARS YEARS
---------------------- ----------- ----------- ----------- ----------- -----------

Long Term Debt $ 106,567 $ 1,867 $ 7,035 $ 7,035 $ 90,630
Building Lease 264 132 132 -- --
----------- ----------- ----------- ----------- -----------
Total $ 106,831 $ 1,999 $ 7,167 $ 7,035 $ 90,630
=========== =========== =========== =========== ===========

While we can give no assurance, we currently believe that our cash
flow from operations coupled with our cash and marketable securities on hand
will provide sufficient capital resources and liquidity to fund our planned
capital expenditures, investments in and advances to affiliates, and semiannual
interest payment obligations for the next 12 months. Our expectation is based
upon our current estimate of projected prices, the purchase of a WTI crude oil
"put" (discussed above) and production levels, and our assumptions that there
will be no further disruptions to our production and that PDVSA will timely pay
our invoices. Actual results could be materially affected if there is a
significant change in our expectations or assumptions. Future cash flows are
subject to a number of variables including, but not limited to, the level of
production and prices, as well as various economic and political conditions that
have historically affected the oil and natural gas business. Additionally,
prices for oil are subject to fluctuations in response to changes in supply,
market uncertainty and a variety of factors beyond our control.

We currently have a significant debt obligation of $85 million payable
in November 2007. Our ability to meet our debt obligation and to reduce our
level of debt depends on the successful implementation of our strategic
objectives.

31

EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION

Our results of operations and cash flow are affected by changing oil
prices. Fluctuations in oil and natural gas prices may affect our total planned
development activities and capital expenditure program.

There are presently no restrictions in Russia that restrict converting
U.S. dollars into local currency or local currency into U.S. dollars for routine
business operations, such as the payments of invoices, and debt obligations
within the Russian Federation. As noted above under CAPITAL RESOURCES AND
LIQUIDITY, Venezuela imposed currency exchange restrictions on February 5, 2003.
We are unable to predict the impact of the currency controls on us or
Benton-Vinccler as the Government has not issued final regulations.

Within the United States, inflation has had a minimal effect on us,
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, our
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 with 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, 2002, our net foreign exchange gain
attributable to our international operations was $4.6 million. However, there
are many factors affecting foreign exchange rates and resulting exchange gains
and losses, many of which are beyond our control. We have 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 for us to predict the extent to which we may be affected by future
changes in exchange rates and exchange controls.

CRITICAL ACCOUNTING POLICIES

Principles of Consolidation

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 we have significant influence.
All intercompany profits, transactions and balances have been eliminated. We
account for our investment in Geoilbent and Arctic Gas based on a fiscal year
ending September 30.

Oil and natural gas revenue is accrued monthly based on sales. Each
quarter, Benton-Vinccler invoices PDVSA based on barrels of oil accepted by
PDVSA during the quarter, using quarterly adjusted U.S. dollar contract service
fees per barrel.

Property and Equipment

We follow 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 natural gas reserves are capitalized as incurred, including exploration
overhead. 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. We regularly evaluate our unproved properties on a
country-by-country basis for possible impairment. If we abandon all exploration
efforts in a country where no proved reserves are assigned, all exploration and
acquisition costs associated with the country are expensed. Due to the
unpredictable nature of exploration drilling activities, the amount and timing
of impairment expenses are difficult to predict with any certainty.

The full cost method of accounting uses proved reserves in the
calculation of depletion, depreciation and amortization. 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.
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

32

and economic changes. The estimates are based on current technology and economic
conditions, and we consider 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 or for which transportation and/or marketing contracts are not in
place. Changes in previous estimates of proved reserves result from new
information obtained from production history and changes in economic factors. A
large portion of our proved reserves base from consolidated operations is
comprised of oil and gas properties that are sensitive to oil price volatility.
We are susceptible to significant upward and downward revisions to our proved
reserve volumes and values as a result of changes in year end oil and gas prices
and the corresponding adjustment to the projected economic life of such
properties. Prices for oil and gas are likely to continue to be volatile,
resulting in future revision to our proved reserve base. We perform a quarterly
cost center ceiling test of our oil and gas properties under the full cost
accounting rules of the Securities and Exchange Commission. These rules
generally require that we price our future oil and gas production at the oil and
gas prices in effect at the end of each fiscal quarter and require a write-down
if our capitalized costs exceed this "ceiling," even if prices declined for only
a short period of time. We have had no write-downs due to these ceiling test
limitations since 1998. Given the volatility of oil and gas prices, it is likely
that our estimate of discounted future net revenues from proved oil and gas
reserves will change in the near term. If oil and gas prices decline
significantly in the future, even if only for a short period of time,
write-downs of our oil and gas properties could occur. Write-downs required by
these rules do not directly impact our cash flows from operating activities.

Income Taxes

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 carry
forwards. 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

We have significant operations outside of the United States,
principally in Venezuela and an equity investment in Russia. Amounts denominated
in non-U.S. currencies are re-measured in United States dollars, and all
currency gains or losses are recorded in the statement of income. We attempt to
manage our operations in a manner to reduce our exposure to foreign exchange
losses. However, there are many factors that affect foreign exchange rates and
resulting exchange gains and losses, many of which are beyond our influence. We
have 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
we may be affected by future changes in exchange rates.

New Accounting Pronouncements

In September 2001, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 143, Accounting for Asset
Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of
the related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method. SFAS No. 143 is
effective for fiscal years beginning after September 15, 2002. We will adopt
SFAS No. 143 effective January 1, 2003, and such adoption will not materially
impact the financial statements since our PDVSA operating service agreement
provides that all wells revert to PDVSA at contract expiration and intervening
abandonment obligations are minor. Further we believe the adoption of SFAS No.
143 by Geoilbent will not materially impact our equity in earnings given that
the fair value of such obligations are not material as of September 30, 2002.

In May 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". SFAS 145 rescinds the automatic treatment of gains or losses from
extinguishment of debt as extraordinary items as outlined in APB Opinion No. 30,
"Reporting the Results of Operations, Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions". As allowed under the provisions of SFAS 145, we had

33

decided to adopt SFAS 145 early. Accordingly, all gains on early extinguishment
of debt have been reclassified to other non-operating income in the accompanying
consolidated financial statements.

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities". The standard requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
Examples of costs covered by the standard include lease termination costs and
certain employee severance costs that are associated with a restructuring,
discontinued operation, plant closing, or other exit or disposal activity. SFAS
146 replaces Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)". The provisions of this
statement shall be effective for exit or disposal activities initiated after
December 31, 2002. The Company will account for exit or disposal activities
initiated after December 31, 2002, in accordance with the provisions of SFAS No.
146.

In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure an amendment of FASB
Statement No. 123". The standard amends SFAS Statement No. 123 that provides
alternative methods of transition for an entity that voluntarily changes to the
fair value based method of accounting for stock-based employee compensation. In
addition, this statement amends the disclosure requirements of SFAS No. 123 to
require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The Company intends to adopt the
"Prospective method" which will apply the recognition provisions to all employee
awards granted, modified, or settled in 2003.

The weighted average fair value of the stock options granted from our
stock option plans during 2002, 2001 and 2000 was $4.84, $1.33 and $1.65,
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:

2002 2001 2000
----------- ----------- -----------

Expected life................................... 10.0 years 10.0 years 9.1 years
Risk-free interest rate......................... 5.0% 5.1% 6.1%
Volatility...................................... 74% 72% 74%
Dividend Yield.................................. 0% 0% 0%

We accounted for stock-based compensation in accordance with Accounting
Principles Board Opinion No. 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, our pro forma net
income and earnings per share for 2002, 2001 and 2000 would have been as follows
(in thousands, except per share data):

2002 2001 2000
--------- --------- ---------

Net income as reported................................. $ 100,362 $ 43,237 $ 20,488

Add: Stock-based employee compensation expense
included in reported net income due to acceleration
of vesting of former employees......................... 915 35 110

Deduct: Total stock-based employee compensation
expense determined under fair value based method for
all grants awarded since January 1, 1995............... (2,905) (2,459) (4,374)
--------- --------- ---------

Net income ............................................ $ 98,372 $ 40,813 $ 16,224
========= ========= =========
Net income per common share:
Basic............................................... $ 2.87 $ 1.20 $ 0.53
========= ========= =========
Diluted............................................. $ 2.75 $ 1.20 $ 0.53
========= ========= =========

In November 2002 FASB interpretation, or FIN 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantee of Indebtedness of Others" was issued. FIN 45 requires that upon

34

issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions for
initial recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's initial
application may not be revised or restated to reflect the effect of the
recognition and measurement provisions of FIN 45. The disclosure requirements
are effective for financial statements of both interim and annual periods that
end after December 15, 2002. As of December 31, 2002, the Company does not have
any guarantor obligations.

In January 2003 FASB Interpretation 46, or FIN 46, "Consolidation of
Variable Interest Entities" was issued. FIN 46 identifies certain off-balance
sheet arrangements that meet the definition of a variable interest entity (VIE).
The primary beneficiary of a VIE is the party that is exposed to the majority of
the risks and/or returns of the VIE. In future accounting periods, the primary
beneficiary will be required to consolidate the VIE. In addition, more extensive
disclosure requirements apply to the primary beneficiary, as well as other
significant investors. We do not believe we participate in any arrangement that
would be subject to the provisions of FIN 46.

In November 2002, the International Practices Task Force concluded that
Russia has ceased being a highly inflationary economy as of January 1, 2003. As
a result of the Task Force conclusion, companies reporting under US GAAP in
Russia will be required to apply the guidance contained in Emerging Issues Task
Force ("EITF") No. 92-4 and EITF No. 92-8 as of January 1, 2003. We have not yet
estimated the effect that EITF No. 92-4 and EITF No. 92-8 will have on Geoilbent
or our equity position.

35

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from adverse changes in oil and natural
gas prices, interest rates, foreign exchange and political risk, as discussed
below.

OIL PRICES

As an independent oil producer, our 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
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 our control. Historically, prices received
for oil production have been volatile and unpredictable, and such volatility is
expected to continue. Through February 14, 2003, we utilized a costless collar
hedge transaction with respect to a portion of our oil production to achieve a
more predictable cash flow, establish an acceptable rate of return on our
Tucupita drilling program, as well as to reduce our exposure to price
fluctuations. Benton-Vinccler has hedged a portion of its 2003 oil production by
purchasing a WTI crude oil "put" to protect its 2003 cash flow. 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. See Note 1 -
Derivatives and Hedging for a complete discussion of our derivative activity.

INTEREST RATES

Total long-term debt at December 31, 2002 of $104.7 million consisted
of fixed-rate senior unsecured notes maturing in 2007 ($85.0 million).
Benton-Vinccler has $18.2 million U.S. Dollar denominated and 1.5 million
Bolivar denominated variable rate loans. A hypothetical 10 percent adverse
change in the interest rate would not have had a material affect on our results
of operations.

FOREIGN EXCHANGE

For the Venezuelan operations, oil and gas sales are received under a
contract in effect through 2012 in U.S. dollars; expenditures are both in U.S.
dollars and local currency. For Geoilbent, a majority of the oil sales are
received in Rubles; expenditures are both in U.S. dollars and local currency,
although a larger percentage of the expenditures are in local currency. We have
utilized no currency hedging programs to mitigate any risks associated with
operations in these countries, and therefore our financial results are subject
to favorable or unfavorable fluctuations in exchange rates and inflation in
these countries. Venezuela has recently imposed currency exchange controls (see
CAPITAL RESOURCES AND LIQUIDITY above).

POLITICAL RISK

The stability of government in Venezuela and the government's
relationship with the state-owned national oil company, PDVSA, remain
significant risks for our company. PDVSA is the sole purchaser of all Venezuelan
oil and gas production. In April 2002 there was a failed attempt to remove the
President of Venezuela. During this period, sales were curtailed but our oil
production was not interrupted, but it did delay the importation of critical
equipment, which contributed to the slowdown in our drilling operations. From
December 14, 2002 through February 6, 2003, no sales were made because of
PDVSA's inability to accept our oil due to the national civil work stoppage. As
a result, 2002 sales were reduced by approximately 550,000 barrels and sales in
2003 were reduced by an estimated 1.2 million barrels. While the situation has
stabilized and production is returning to normal, there continues to be
political and economic uncertainty that could lead to another disruption of our
sales. As a result of the national civil work stoppage, the Government of
Venezuela terminated several thousand PDVSA employees and announced a
decentralization of PDVSA's operations. While the effect of these changes cannot
be predicted, it could adversely affect PDVSA's ability to manage its contracts
and meet its obligations with its suppliers and vendors, such as
Benton-Vinccler. As a result of the situation in PDVSA, its payment to
Benton-Vinccler for crude delivered in the fourth quarter 2002 was late by seven
days. We believe that the payment demonstrates PDVSA's commitment to building
its production levels back to full capacity and returning to more normalized
business relations with its customers and suppliers. While we have substantial
cash reserves to withstand a future disruption, a prolonged loss of sales or a
failure or delay by PDVSA to pay our invoices could have a material adverse
effect on our financial condition.

36

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item is included herein on pages S-1 through
S-37.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

37

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*

Number of securities
Number of remaining
securities to be available for
issued upon future issuance
exercise of Weighted-average under equity
outstanding exercise price compensation
options, of outstanding plans (excluding
warrants and options, warrants securities reflected
rights and rights in column (a)
Plan Category (a) (b) (c)
------------------ --------------- ---------------- --------------------

Equity compensation plans approved by
security holders 4,244,463 $8.68 310,000
Equity compensation plans not approved by
security holders(1) 1,170,650 2.92
----------- ---------- -----------
Total 5,415,113 $7.43 310,000
=========== ========== ===========

(1) See Note 6 of Notes to Consolidated Financial Statements for a
description of options issued to individuals other than officers,
directors or employees of the Company. The 1999 Stock Option Plan
permits the granting of stock options to purchase up to 2,500,000
shares of our common stock in the form of 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, subject
to the dollar limitations imposed by the Internal Revenue Code. In
the event of a change in control of our company, all outstanding
options become immediately exercisable to the extent permitted by
the plan. Options granted to employees under the 1999 Stock Option
Plan vest 50 percent after the first year and 25 percent after each
of the following two years, or they vest ratably over a three-year
period, 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 and consultants 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. These were the only
compensation plans in effect that were adopted without the approval
of the Company's stockholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS*

* Reference is made to information under the captions "Election of Directors",
"Executive Officers", "Executive Compensation", "Stock Ownership", and "Certain
Relationships and Related Transactions" in our Proxy Statement for the 2003
Annual Meeting of Shareholders.

ITEM 14. CONTROLS AND PROCEDURES

In its recent Release No. 34-46427, effective August 29, 2002, the SEC, among
other things, adopted rules requiring reporting companies to maintain disclosure
controls and procedures to provide reasonable assurance that a registrant is
able to record, process, summarize and report the information required in the
registrant's quarterly and annual reports under the Securities Exchange Act of
1934 (the "Exchange Act"). While we believe that our existing disclosure
controls and procedures have been effective to accomplish these objectives, we
intend to continue to examine, refine and formalize our disclosure controls and
procedures and to monitor ongoing developments in this area.

Our principal executive officer and our principal financial officer have
informed us that, based upon their evaluation as of December 31, 2002, of our
disclosure controls and procedures (as defined in Rule 13a-14(c) and Rule
15d-14(c) under the Exchange Act), they have concluded that those disclosure
controls and procedures are effective.

38

There have been no changes in our internal controls or in other factors known to
us that could significantly affect these controls subsequent to their
evaluation, nor any corrective actions with regard to significant deficiencies
and material weaknesses.

39

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. Index to Financial Statements: Page
----
Report of Independent Accountants .................................S-1

Consolidated Balance Sheets at December 31, 2002 and 2001..........S-2

Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001 and 2000...................................S-3

Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2002, 2001, and 2000......................S-4

Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001, and 2000..................................S-5

Notes to Consolidated Financial Statements.........................S-7

2. Consolidated Financial Statement Schedules:

Schedule II - Valuation and Qualifying Accounts

Schedule III - Financial Statements and Notes for LLC Geoilbent

All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or the notes
thereto.

3 Exhibits:

3.1 Certificate of Incorporation filed September 9, 1988
(Incorporated by reference to Exhibit 3.1 to our
Registration Statement (Registration No. 33-26333)).

3.2 Amendment to Certificate of Incorporation filed June 7, 1991
(Previously filed as an exhibit to our S-1 Registration
Statement (Registration No. 33-39214)).

3.3 Restated Bylaws (Incorporated by reference to Exhibit 3.3 to
our Form 10-Q, filed August 13, 2001).

4.1 Form of Common Stock Certificate (Previously filed as an
exhibit to our S-1 Registration Statement (Registration No.
33-26333)).

4.2 Certificate of Designation, Rights and Preferences of the
Series B. Preferred Stock of Benton Oil and Gas Company,
filed May 12, 1995. (Previously filed as an Exhibit 4.1 to
our Form 10-Q filed on May 13, 2002, File No. 1-10762.)

4.3 Rights Agreement between Benton Oil and Gas Company and
First Interstate Bank, Rights Agent dated April 28, 1995.
(Previously filed as Exhibit 4.1 to our Form 10-Q filed on
August 13, 2002, File No. 1-10762.)

10.1 Form of Employment Agreements (Exhibit 10.19) (Previously
filed as an exhibit to our S-1 Registration Statement
(Registration No. 33-26333)).

10.2 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 our S-1 Registration
Statement (Registration No. 33-46077)).

40

10.3 Operating Service Agreement between Benton Oil and Gas
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 our S-1 Registration Statement (Registration No.
33-52436)).

10.4 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 percent Senior Notes due 2007. (Incorporated
by reference to Exhibit 10.1 to our Form 10-Q for the
quarter ended September 30, 1997, File No. 1-10762.)

10.5 Note payable agreement dated March 8, 2001 between
Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a
note in the principal amount of $6,000,000 with interest at
LIBOR plus five percent, for financing of Tucupita Pipeline
(Incorporated by reference to Exhibit 10.24 to our Form
10-Q, filed on May 15, 2001, File No. 1-10762).

10.6 Note payable agreement dated March 8, 2001 between
Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a
note in the principal amount of 4,435,200,000 Venezuelan
Bolivars (approximately $6.3 million) at a floating interest
rate, for financing of Tucupita Pipeline (Incorporated by
reference to Exhibit 10.25 to our Form 10-Q, filed on May
15, 2001, File No. 1-10762.).

10.7 Change of Control Severance Agreement effective May 4, 2001
(Incorporated by reference to Exhibit 10.26 to our Form
10-Q, filed on August 13, 2001, File No. 1-10762.).

10.8 Alexander E. Benton Settlement and Release Agreement
effective May 11, 2001 (Incorporated by reference to Exhibit
10.27 to our Form 10-Q, filed on August 13, 2001, File No.
1-10762.).

10.9 First Amendment to Change of Control Severance Plan
effective June 5, 2001 (Incorporated by reference to Exhibit
10.31 to our Form 10-Q, filed on August 13, 2001, File No.
1-10762.).

10.10 Sale and Purchase Agreement dated February 27, 2002 between
Benton Oil and Gas Company and Sequential Holdings Russian
Investors Limited regarding the sale of Benton Oil and Gas
Company's 68 percent interest in Arctic Gas Company.
(Incorporated by reference to Exhibit 10.25 to our Form 10-K
filed on March 28, 2002, File No. 1-10762.)

10.11 2001 Long Term Stock Incentive Plan (Incorporated by
reference to Exhibit 4.1 to our S-8 (Registration Statement
No. 333-85900)).

10.12 Subordinated Loan Agreement US$2,500,000 between Limited
Liability Company "Geoilbent" as borrower, and Harvest
Natural Resources, Inc. as lender. (Incorporated by
reference to Exhibit 10.2 to our Form 10-Q filed on August
13, 2002.)

10.13 Addendum No. 2 to Operating Services Agreement Monagas SUR
dated 19th September, 2002. (Incorporated by reference to
Exhibit 10.4 to our Form 10-Q filed on November 8, 2002,
File No. 1-10762.)

10.14 Bank Loan Agreement between Banco Mercantil, C.A. and
Benton-Vinccler C.A. dated October 1, 2002. (Incorporated by
reference to Exhibit 10.5 to our Form 10-Q filed on November
8, 2002, File No. 1-10762.)

10.15 Guaranty issued by Harvest Natural Resources, Inc. dated
September 26, 2002. (Incorporated by reference to Exhibit
10.6 to our Form 10-Q filed on November 8, 2002, File No.
1-10762.)

10.16 Amending and Restating the Credit Agreement between Limited
Liability Company "Geoilbent" and European Bank for
Reconstruction and Development dated 23rd September 2002.
(Incorporated by reference to Exhibit 10.7 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)

41

10.17 Amendment Agreement relating to Performance, Subordination
and Share Retention Agreement dated 30th September, 2002.
(Incorporated by reference to Exhibit 10.8 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)

10.18 Amending and Restating the Agreement for Pledge of Shares in
Limited Liability Company "Geoilbent" dated 23rd June, 1997.
(Incorporated by reference to Exhibit 10.9 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)

10.19 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Peter J. Hill. (Incorporated by
reference to Exhibit 10.10 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)

10.20 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Steven W. Tholen. (Incorporated
by reference to Exhibit 10.11 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)

10.21 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Kerry R. Brittain. (Incorporated
by reference to Exhibit 10.12 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)

10.22 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by
reference to Exhibit 10.13 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)

21.1 List of subsidiaries.

23.1 Consent of PricewaterhouseCoopers LLP. - Houston

23.2 Consent of ZAO PricewaterhouseCoopers - Moscow

23.3 Consent of Ryder Scott Company, L.P.

(b) Reports on Form 8-K

On December 11, 2002, we filed an 8-K for a press release dated
December 10, 2002, announcing the implementation of an operational contingency
plan for the Company's operations in Venezuela.

On December 19, 2002, we filed an 8-K for a press release dated
December 18, 2002, reporting that, as a result of the ongoing disruptions in
Venezuela, the Company is proceeding with its previously announced operational
contingency plan for its operations in Venezuela.

42

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors
and Stockholders of Harvest Natural Resources, Inc.

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of stockholders' equity and of cash flows
present fairly, in all material respects, the financial position of Harvest
Natural Resources, Inc. and its subsidiaries at December 31, 2002 and 2001, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the related financial statement Schedule II - Valuation and Qualifying Accounts
listed in the index appearing under Item 15(a)(2) on page 40 presents fairly,
in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, 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 our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company's
total consolidated revenues relate to operations in Venezuela. In addition, the
Venezuelan government has implemented foreign currency controls and its economic
activities have been impacted by national work stoppages.

PricewaterhouseCoopers LLP

Houston, Texas
March 28, 2003

S-1

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

DECEMBER 31,
-------------------------------
2002 2001
----------- -----------
(IN THOUSANDS, EXCEPT PER
SHARE DATA)

ASSETS
Current Assets:
Cash and cash equivalents.................................................... $ 64,501 $ 9,024
Deposits and restricted cash................................................. 1,812 12
Marketable securities........................................................ 27,388 --
Accounts and notes receivable:
Accrued oil sales......................................................... 27,359 23,138
Joint interest and other, net............................................. 8,002 9,520
Prepaid expenses and other................................................... 2,969 1,839
----------- -----------
Total Current Assets................................................... 132,031 43,533
Restricted Cash................................................................. 16 16
Other Assets.................................................................... 2,520 4,718
Deferred Income Taxes........................................................... 4,082 57,700
Investments In and Advances To Affiliated Companies............................. 51,783 100,498
Property and Equipment:
Oil and gas properties (full cost method-costs of $2,900 and $16,808
excluded from amortization in 2002 and 2001, respectively)................ 576,601 533,950
Furniture and fixtures....................................................... 7,503 7,399
----------- -----------
584,104 541,349
Accumulated depletion, depreciation, and amortization........................ (439,344) (399,663)
----------- -----------
Net Property and Equipment............................................. 144,760 141,686
----------- -----------
$ 335,192 $ 348,151
=========== ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable, trade and other............................................ $ 3,804 $ 8,132
Accrued expenses............................................................. 20,644 25,840
Accrued interest payable..................................................... 1,405 3,894
Income taxes payable......................................................... 6,880 3,821
Commodity hedging contract................................................... 430 --
Current portion of long-term debt............................................ 1,867 2,432
----------- -----------
Total Current Liabilities.............................................. 35,030 44,119
Long-Term Debt.................................................................. 104,700 221,583
Commitments and Contingencies................................................... -- --
Minority Interest............................................................... 24,145 14,826
Stockholders' Equity:
Preferred stock, par value $0.01 a share; Authorized 5,000 shares;
outstanding, none Common stock, par value $0.01 a share; Authorized 80,000
shares at December 31, 2002 and 2001; issued 35,900 and 34,164 at
December 31, 2002 and 2001................................................... 359 342
Additional paid-in capital................................................... 173,559 168,108
Retained earnings (accumulated deficit)...................................... 234 (100,128)
Treasury stock, at cost, 650 shares and 50, respectively..................... (2,835) (699)
----------- -----------
Total Stockholders' Equity............................................. 171,317 67,623
----------- -----------
$ 335,192 $ 348,151
=========== ===========

See accompanying notes to consolidated financial statements.

S-2

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)

REVENUES
Oil sales......................................................... $ 127,015 $ 122,386 $ 140,284
Loss on ineffective hedge activity................................ (284) -- --
----------- ----------- -----------
126,731 122,386 140,284
----------- ----------- -----------

EXPENSES
Operating expenses................................................ 33,950 42,759 47,430
Depletion, depreciation and amortization.......................... 26,363 25,516 17,175
Write-down of oil and gas properties and impairments.............. 14,537 468 1,346
General and administrative........................................ 16,504 20,072 16,739
Bad debt recovery................................................. (3,276) -- --
Taxes other than on income........................................ 4,068 5,370 4,390
----------- ----------- -----------
92,146 94,185 87,080
----------- ----------- -----------

Income from Operations............................................... 34,585 28,201 53,204

Other Non-Operating Income (Expense)
Gain on sale of investment........................................ 144,029 -- --
Gain on early extinguishment of debt.............................. 874 -- 3,960
Investment earnings and other..................................... 2,080 3,088 8,559
Interest expense.................................................. (16,310) (24,875) (28,973)
Net gain on exchange rates........................................ 4,553 768 326
----------- ----------- -----------
135,226 (21,019) (16,128)
----------- ----------- -----------
Income from Consolidated Companies Before Income
Taxes and Minority Interest....................................... 169,811 7,182 37,076
Income Tax Expense (Benefit)......................................... 60,295 (35,698) 14,032
----------- ----------- -----------
Income Before Minority Interest...................................... 109,516 42,880 23,044
Minority Interest in Consolidated Subsidiary Companies............... 9,319 5,545 7,869
----------- ----------- -----------
Income from Consolidated Companies................................... 100,197 37,335 15,175
Equity in Net Earnings of Affiliated Companies....................... 165 5,902 5,313
----------- ----------- -----------
Net Income........................................................... $ 100,362 $ 43,237 $ 20,488
=========== =========== ===========

Net Income Per Common Share:
Basic............................................................ $ 2.90 $ 1.27 $ 0.67
=========== =========== ===========

Diluted.......................................................... $ 2.78 $ 1.27 $ 0.66
=========== =========== ===========

See accompanying notes to consolidated financial statements.

S-3

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)

RETAINED
COMMON ADDITIONAL EARNINGS
SHARES COMMON PAID-IN (ACCUMULATED TREASURY
ISSUED STOCK CAPITAL DEFICIT) STOCK TOTAL
----------- ----------- ----------- ----------- ----------- -----------

BALANCE AT JANUARY 1, 2000.... 29,627 $ 296 $ 147,078 $ (163,853) $ (699) $ (17,178)
Issuance of common shares:
Exercise of stock options 85 1 316 - - 317
Extension of warrants...... - - 12 - - 12
Repurchase of debt............ 4,160 42 9,223 - - 9,265
Net Income.................... - - - 20,488 - 20,488
----------- ----------- ----------- ---------- ----------- -----------
BALANCE AT DECEMBER 31, 2000.. 33,872 339 156,629 (143,365) (699) 12,904

Issuance of common shares:
Non-employee director
compensation............. 292 3 471 - - 474
Tax benefits related to stock
option compensation......... - - 11,008 - - 11,008
Net Income.................... - - - 43,237 - 43,237
----------- ----------- ----------- ---------- ----------- -----------
BALANCE AT DECEMBER 31, 2001.. 34,164 342 $ 168,108 $ (100,128) $ (699) $ 67,623

Issuance of common shares:
Non-employee director
compensation............. 46 - 543 - - 543
Employee compensation...... 175 2 663 - - 665
Exercise of stock options.. 1,515 15 4,245 - - 4,260
Treasury stock (600 shares)... - - - - (2,136) (2,136)
Net Income.................... - - - 100,362 - 100,362
----------- ----------- ----------- ---------- ----------- -----------
BALANCE AT DECEMBER 31, 2002.. 35,900 $ 359 $ 173,559 $ 234 $ (2,835) $ 171,317
=========== =========== =========== ========== =========== ===========

See accompanying notes to consolidated financial statements.

S-4

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

YEARS ENDED DECEMBER 31,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(IN THOUSANDS)

Cash Flows From Operating Activities:
Net income ....................................................... $ 100,362 $ 43,237 $ 20,488
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation and amortization....................... 26,363 25,516 17,175
Write-down and impairment of oil and gas properties............ 14,537 468 1,346
Amortization of financing costs................................ 1,745 1,179 1,375
(Gain) loss on disposition of assets........................... (144,029) (336) 60
Equity in net earnings of affiliated companies................. (165) (5,902) (5,313)
Allowance and write-off of employee notes and accounts
receivable................................................... (2,987) 365 331
Non-cash compensation related charges.......................... 1,458 474 --
Minority interest in undistributed earnings of subsidiaries.... 9,319 5,545 7,869
Gain from early extinguishment of debt......................... (874) -- (3,960)
Tax benefits related to stock option compensation.............. -- 11,008 --
Deferred income taxes.......................................... 53,618 (53,407) 7,893
Changes in operating assets and liabilities:
Accounts and notes receivable.................................. (1,972) 11,756 (12,780)
Prepaid expenses and other..................................... (1,130) 565 (769)
Accounts payable............................................... (4,328) (4,671) 9,487
Accrued interest payable....................................... (2,489) 161 (953)
Accrued expenses............................................... (10,290) 43 7,971
Commodity hedging contract..................................... 430 -- --
Income taxes payable........................................... 3,059 607 1,543
----------- ----------- -----------
Net Cash Provided by Operating Activities...................... 42,627 36,608 51,763
----------- ----------- -----------
Cash Flows from Investing Activities:
Proceeds from sale of investment.................................. 189,841 -- 800
Additions of property and equipment............................... (43,346) (43,364) (57,196)
Investment in and advances to affiliated companies................ 9,185 (16,855) (11,071)
Increase in restricted cash....................................... (2,800) (57) (271)
Decrease in restricted cash....................................... 1,000 10,961 35,800
Purchases of marketable securities................................ (353,478) (15,067) (12,638)
Maturities of marketable securities............................... 326,090 16,370 15,804
----------- ----------- -----------
Net Cash Provided by (Used In) Investing Activities............ 126,492 (48,012) (28,772)
----------- ----------- -----------
Cash Flows from Financing Activities:
Net proceeds from exercise of stock options....................... 3,345 -- 330
Proceeds from issuance of short term borrowings and notes
payable......................................................... 15,500 21,112 15,087
Payments on short term borrowings and notes payable............... (132,138) (15,746) (47,488)
(Increase) decrease in other assets............................... (349) (70) 3,065
----------- ----------- -----------
Net Cash Provided by (Used In) Financing Activities............ (113,642) 5,296 (29,006)
----------- ----------- -----------
Net Increase (Decrease) in Cash and Cash Equivalents........... 55,477 (6,108) (6,015)
Cash and Cash Equivalents at Beginning of Year....................... 9,024 15,132 21,147
----------- ----------- -----------
Cash and Cash Equivalents at End of Year............................. $ 64,501 $ 9,024 $ 15,132
=========== =========== ===========

Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense.................... $ 19,201 $ 25,721 $ 28,326
=========== =========== ===========
Cash paid during the year for income taxes........................ $ 3,935 $ 3,057 $ 2,950
=========== =========== ===========

See accompanying notes to consolidated financial statements.

S-5

SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:

For the three years ended December 31, 2002, we recorded an allowance for
doubtful accounts related to interest accrued on the remaining amount owed to us
by our former chief executive officer, A. E. Benton. During the year ended
December 31, 2002, we reversed a portion of such allowance as a result of our
collection of certain amounts owed to the Company including the portions of the
note secured by our stock and other properties (see Note 13 - Related Party
Transactions).

See accompanying notes to consolidated financial statements.

S-6

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements

NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

Harvest Natural Resources, Inc. (formerly known as Benton Oil and Gas Company)
is engaged in the exploration, development, production and management of oil and
gas properties. We conduct our business principally in Venezuela and through our
equity interest in our entity in Russia.

PRINCIPLES OF CONSOLIDATION

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 we have significant influence. All
intercompany profits, transactions and balances have been eliminated. We account
for our investment in LLC Geoilbent ("Geoilbent") and Arctic Gas Company
("Arctic Gas"), based on a fiscal year ending September 30 (see Note 2 -
Investments In and Advances to Affiliated Companies).

REVENUE RECOGNITION

Oil revenue is accrued monthly based on production and delivery. Each quarter,
Benton-Vinccler invoices PDVSA or affiliates based on barrels of oil accepted by
PDVSA during the quarter, using quarterly adjusted U.S. dollar contract service
fees per barrel. The operating service agreement provides for Benton-Vinccler to
receive an operating fee for each barrel of crude oil delivered and 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.

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 and loan agreements and is classified as current
or non-current based on the terms of the agreements.

MARKETABLE SECURITIES

Marketable securities are carried at cost. The marketable securities we may
purchase are limited to those defined as Cash Equivalents in the indentures for
our senior unsecured note. 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. Our marketable securities at cost, which approximates fair value,
consisted of $27.4 million in commercial paper at December 31, 2002.

CREDIT RISK AND OPERATIONS

All of our total consolidated revenues relate to operations in Venezuela. During
the year ended December 31, 2002, our Venezuelan crude oil production
represented all of its total production from consolidated companies, and our
sole source of revenues related to such Venezuelan production is PDVSA, which
maintains full ownership of all hydrocarbons in its fields. On December 2, 2002,
employers' and workers' organizations, together with political and civic
organizations began a national civic work stoppage, which has seriously affected
many of the country's economic activities, in particular, the oil industry. As a
result of the strike, we were unable to deliver crude oil and

S-7

hence generate revenues from PDVSA between December 14, 2002 and February 6,
2003. While Venezuelan production has resumed and we have received payment for
its revenues from PDVSA, there continues to be political and economic
uncertainty that could lead to another disruption of our revenues. Further, on
January 21, 2003, the Venezuelan Government has closed foreign currency markets
and announced its intention to implement currency exchange controls aimed at
restricting the convertibility of the Venezuelan Bolivar and the transfer of
funds out of Venezuela. The Venezuelan Government has created a new Currency
Exchange Agency ("CADIVI") which will be responsible for the administration of
exchange controls. The closure of the foreign currency markets has limited
Benton-Vinccler's ability to obtain Bolivars to make payments to employees and
vendors and has restricted our ability to repatriate funds from Venezuela in
order to meet our cash requirements. Detailed regulations for exchange controls
have not yet been issued by CADIVI. It is not possible to estimate the effects
that any further disruptions in Venezuelan crude oil sales or that prolonged
currency controls could have on operations and results. Management believes that
we have sufficient cash and does not expect the currency conversion restrictions
to adversely affect our ability to meet our short-term obligations.

DERIVATIVES AND HEDGING

We began in the third quarter of 2002 to use a derivative instrument to manage
market risk resulting from fluctuations in the commodity price of crude oil.
Benton-Vinccler, C.A. (See Note 10 - Venezuelan Operations) entered into a
commodity contract (costless collar), which requires payments to (or receipts
from) counterparties based on a West Texas Intermediate crude oil floor price of
$23.00 and a ceiling price of $30.15 for 6,000 barrels of oil per day. The
notional amount of this financial instrument is based on expected sales of crude
oil production from drilling of the Tucupita development wells. This instrument
protects our projected investment return by reducing the impact of an unexpected
downward crude oil price movement. The hedge covers expected sales of production
for six months beginning in mid-August 2002. Due to the pricing structure of our
Venezuelan oil, this collar had the economic effect of hedging approximately
12,000 barrels of oil per day until sales were ceased on December 14, 2002, due
to the Venezuelan national civil work stoppage. In order for a derivative
instrument to qualify for hedge accounting, there must have been a clear
correlation between the derivative instrument and the forecasted transaction.
Correlation of the commodity contract was determined by evaluating whether the
contract gains and losses would substantially offset the effects of price
changes on the underlying crude oil sales volumes. To the extent that
correlation exists between the contract and the underlying crude oil sales
volumes, realized gains or losses and related cash flows arising from the
contracts are recognized as a component of oil revenue in the same period as the
sale of the underlying volumes.

This derivative contract has been designated as a cash flow hedge. For all
derivatives designated as cash flow hedges, we formally document the
relationship between the derivative contract and the hedged item, as well as the
risk management objective for entering into the contract. To be designated as a
cash flow hedge transaction, the relationship between the derivative and the
hedged item must be highly effective in achieving the offset of changes in cash
flows attributable to the risk both at the inception of the derivative and on an
ongoing basis. We measure the hedge effectiveness on a quarterly basis and hedge
accounting is discontinued prospectively if it is determined that the derivative
is no longer effective in offsetting changes in the cash flows of the hedged
item.

Statement of Financial Accounting Standards No. 133, as amended, establishes
accounting and reporting standards for derivative instruments and hedging
activities. All derivatives are recorded on the balance sheet at fair value. To
the extent that the hedge is determined to be effective, as discussed above,
changes in the fair value of derivatives for cash flow hedges are recorded each
period in other comprehensive income. Our derivative is a cash flow hedge
transaction in which we hedge the variability of cash flows related to a
forecasted transaction. This derivative instrument was designated as a cash flow
hedge and the changes in the fair value will be reported in other comprehensive
income assuming the highly effective test is met, and has been reclassified to
earnings in the period in which earnings are impacted by the variability of the
cash flows of the hedged item. We determined that the underlying crude oil would
not be delivered due to the cessation of production. Accordingly, hedge
accounting was discontinued and the value of the derivative was recorded as a
revenue reduction in the amount of $0.3 million. In connection with this
instrument we had deposited collateral of $1.8 million as of December 31, 2002
with the counterparty.

S-8

ACCOUNTS AND NOTES RECEIVABLE

Allowance for doubtful accounts related to former employee notes at December 31,
2002 and 2001 was $3.5 million and $6.2 million, respectively (see Note 13 -
Related Party Transactions).

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, which approximates the effective interest method of
amortizing these costs.

PROPERTY AND EQUIPMENT

We follow 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 natural
gas reserves are capitalized as incurred, including exploration overhead of $0.6
million and $1.5 million for the years ended December 31, 2001 and 2000,
respectively, and capitalized interest of $0.9 million and $0.6 million for the
years ended December 31, 2001 and 2000, respectively. There was no capitalized
overhead and interest in 2002. 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. We regularly evaluate our unproved properties on a
country by country basis for possible impairment. If we abandon all exploration
efforts in a country where no proved reserves are assigned, all exploration and
acquisition costs associated with the country are expensed. During 2002, 2001
and 2000, the Company recognized $14.5 million, $0.5 million and $1.3 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.

Excluded costs at December 31, 2002 consisted of the following by year incurred
(in thousands):

PRIOR
TOTAL TO 2000
--------- ---------

Property acquisition costs...................... $ 2,900 $ 2,900
========= =========

All of the excluded costs at December 31, 2002 relate to the acquisition of
Benton Offshore China Company and exploration related to its WAB-21 property.
The ultimate timing of when the costs related to the acquisition of Benton
Offshore China Company will be included in amortizable costs is uncertain.

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 substantially
all attributable to the Venezuelan cost center for the years ended December 31,
2002, 2001 and 2000 was $24.9 million, $22.1 million and $15.3 million ($2.56,
$2.26 and $1.68 per equivalent barrel), respectively.

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 $1.4 million, $3.4
million and $1.8 million for the years ended December 31, 2002, 2001 and 2000,
respectively.

S-9

The major components of property and equipment at December 31 are as follows (in
thousands):

2002 2001
----------- -----------

Proved property costs................................... $ 566,415 $ 501,923
Costs excluded from amortization........................ 2,900 16,808
Material and supply inventories......................... 7,286 15,219
Furniture and fixtures.................................. 7,503 7,399
----------- -----------
584,104 541,349
Accumulated depletion, impairment and depreciation...... (439,344) (399,663)
----------- -----------
$ 144,760 $ 141,686
=========== ===========

We perform a quarterly cost center ceiling test of our oil and gas properties
under the full cost accounting rules of the Securities and Exchange Commission.
No ceiling test write-downs were required.

INCOME TAXES

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. In
the fourth quarter of 2001, a substantial portion of the valuation allowance was
reversed based on the utilization of net operating losses by the Arctic Gas Sale
in 2002.

FOREIGN CURRENCY

We have significant operations outside of the United States, principally in
Venezuela and an equity investment in Russia. Amounts denominated in non-U.S.
currencies are re-measured in United States dollars, and all currency gains or
losses are recorded in the statement of income. We attempt to manage our
operations in a manner to reduce our exposure to foreign exchange losses.
However, there are many factors that affect foreign exchange rates and resulting
exchange gains and losses, many of which are beyond our influence. We have
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 we may
be affected by future changes in exchange rates.

In November 2002, the International Practices Task Force (IPTF) concluded that
Russia has ceased being a highly inflationary economy as of January 1, 2003. As
a result of the Task Force conclusion, companies reporting under US GAAP in
Russia will be required to apply the guidance contained in EITF No. 92-4 and
EITF No. 92-8 as of January 1, 2003. We have not yet estimated the effect that
EITF No. 92-4 and EITF No. 92-8 will have on Geoilbent or our equity position.

FINANCIAL INSTRUMENTS

Our financial instruments that are exposed to concentrations of credit risk
consist primarily of cash and cash equivalents, marketable securities and
accounts receivable. Cash and cash equivalents are placed with commercial banks
with high credit ratings. This diversified investment policy limits our exposure
both to credit risk and to concentrations of credit risk. Accounts receivable
result from oil and natural gas exploration and production activities and our
customers and partners are engaged in the oil and natural gas business. PDVSA
purchases 100 percent of our Venezuelan oil and gas production. Although the
Company does not currently foresee a credit risk associated with these
receivables, collection is dependent upon the financial stability of PDVSA. The
payment for the fourth quarter 2002 sales was delayed until March 7, 2003, which
was approximately seven days late due to the effect of the national civil work
stoppage on PDVSA.

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
aggregate fair value of our senior unsecured notes, based on the last trading
prices at December 31, 2002 and 2001, was approximately $77.4 million and $138.1
million, respectively.

S-10

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. We did not
have any items of other comprehensive income during the three years ended
December 31, 2002 and, in accordance with SFAS 130, have not provided a separate
statement of comprehensive income.

MINORITY INTERESTS

We record a minority interest attributable to the minority shareholder of our
Venezuela subsidiaries. The minority interests in net income and losses are
generally subtracted or added to arrive at consolidated net income.

NEW ACCOUNTING PRONOUNCEMENTS

In September 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method. SFAS No. 143 is
effective for fiscal years beginning after September 15, 2002. We will adopt
SFAS No. 143 effective January 1, 2003 and such adoption will not materially
impact the financial statements since our PDVSA operating service agreement
provides that all wells revert to PDVSA at contract expiration and intervening
abandonment obligations are minor. Accordingly, all gains on early
extinguishment of debt have been reclassified to other non-operating income in
the accompanying consolidated financial statements.

In May 2002, the FASB issued SFAS No. 145, Recission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS
145 rescinds the automatic treatment of gains or losses from extinguishment of
debt as extraordinary items as outlined in APB Opinion No. 30, "Reporting the
Results of Operations, Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions". As allowed under the provisions of SFAS 145, we had decided to
adopt SFAS 145 early (See Note 3 - Long Term Debt and Liquidity).

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities". The standard requires companies to recognize
costs associated with exit or disposal activities when they are incurred rather
than at the date of a commitment to an exit or disposal plan. Examples of costs
covered by the standard include lease termination costs and certain employee
severance costs that are associated with a restructuring, discontinued
operation, plant closing, or other exit or disposal activity. SFAS 146 replaces
Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)". The provisions of this statement
shall be effective for exit or disposal activities initiated after December 31,
2002. The Company will account for exit or disposal activities initiated after
December 31, 2002, in accordance with the provisions of SFAS No. 146.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure an amendment of FASB Statement No.
123". The standard amends SFAS No. 123 that provides alternative methods of
transition for an entity that voluntarily changes to the fair value based method
of accounting for stock-based employee compensation. In addition, this statement
amends the disclosure requirements of SFAS No. 123 to require prominent
disclosures in both annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the method
used on reported results. The Company intends to adopt the "Prospective method"
which will apply the recognition provisions to all employee awards granted,
modified, or settled in 2003.

The weighted average fair value of the stock options granted from our stock
option plans during 2002, 2001 and 2000 was $4.84, $1.33 and $1.65,
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:

S-11

2002 2001 2000
----------- ----------- -----------

Expected life............................... 10.0 years 10.0 years 9.1 years
Risk-free interest rate..................... 5.0% 5.1% 6.1%
Volatility.................................. 74% 72% 74%
Dividend Yield.............................. 0% 0% 0%

We accounted for stock-based compensation in accordance with Accounting
Principles Board Opinion No. 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, our pro forma net
income and earnings per share for 2002, 2001 and 2000 would have been as follows
(in thousands, except per share data):

2002 2001 2000
--------- --------- ---------

Net income as reported................................. $ 100,362 $ 43,237 $ 20,488

Add: Stock-based employee compensation expense
included in reported net income due to acceleration
of vesting of former employees......................... 915 35 110

Deduct: Total stock-based employee compensation
expense determined under fair value based method for
all grants awarded since January 1, 1995............... (2,905) (2,459) (4,374)
--------- --------- ---------

Net income ............................................ $ 98,372 $ 40,813 $ 16,224
========= ========= =========
Net income per common share:
Basic............................................... $ 2.87 $ 1.20 $ 0.53
========= ========= =========
Diluted............................................. $ 2.75 $ 1.20 $ 0.53
========= ========= =========

In November 2002 FASB interpretation, or FIN 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantee of
Indebtedness of Others" was issued. FIN 45 requires that upon issuance of a
guarantee, the guarantor must recognize a liability for the fair value of the
obligation it assumes under that guarantee. FIN 45's provisions for initial
recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's initial
application may not be revised or restated to reflect the effect of the
recognition and measurement provisions of FIN 45. The disclosure requirements
are effective for financial statements of both interim and annual periods that
end after December 15, 2002. As of December 31, 2002, the Company does not have
any guarantor obligations.

In January 2003 FASB Interpretation 46, or FIN 46, "Consolidation of Variable
Interest Entities" was issued. FIN 46 identifies certain off-balance sheet
arrangements that meet the definition of a variable interest entity (VIE). The
primary beneficiary of a VIE is the party that is exposed to the majority of the
risks and/or returns of the VIE. In future accounting periods, the primary
beneficiary will be required to consolidate the VIE. In addition, more extensive
disclosure requirements apply to the primary beneficiary, as well as other
significant investors. We do not believe we participate in any arrangement that
would be subject to the provisions of FIN 46.

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America 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. The most significant estimates pertain to proved
oil, plant products and gas reserve volumes and the future development costs.
Actual results could differ from those estimates.

S-12

RECLASSIFICATIONS

Certain items in 2000 and 2001 have been reclassified to conform to the 2002
financial statement presentation.

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 we exercise over their operations and
management. Investments include amounts paid to the investee companies for
shares of stock and other costs incurred associated with the acquisition and
evaluation of technical data for the oil and natural 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. Arctic Gas was sold on April 12, 2002.

Equity in earnings and losses and investments in and advances to companies
accounted for using the equity method are as follows (in thousands):

GEOILBENT, LTD. ARCTIC GAS COMPANY TOTAL
--------------------- --------------------- ---------------------
2002 2001 2002 2001 2002 2001
--------- --------- --------- --------- -------- ---------

Investments:
In equity in net assets........... $ 28,056 $ 28,056 $ -- $ (1,814) $ 28,056 $ 26,242
Other costs, net of amortization.. 263 (99) -- 28,579 263 28,480
--------- --------- --------- --------- -------- ---------
Total investments................. 28,319 27,957 -- 26,765 28,319 54,722
Advances.............................. 2,527 - -- 28,829 2,527 28,829
Equity in earnings (losses)........... 20,937 19,307 -- (2,360) 20,937 16,947
--------- --------- --------- --------- -------- ---------
Total.......................... $ 51,783 $ 47,264 $ -- $ 53,234 $ 51,783 $ 100,498
========= ========= ========= ========= ======== =========

NOTE 3 - LONG-TERM DEBT AND LIQUIDITY

LONG-TERM DEBT

Long-term debt consists of the following (in thousands):

DECEMBER 31, DECEMBER 31,
2002 2001
------------ ------------

Senior unsecured notes with interest at 9.375%
See description below................................ $ 85,000 $ 105,000
Senior unsecured notes with interest at 11.625%
See description below................................ -- 108,000
Note payable with interest at 6.8%
See description below................................ 3,900 5,100
Note payable with interest at 39.7%
See description below................................ 2,167 5,235
Note payable with interest at 7.8%........................ 15,500 --
Non-interest bearing liability with a face value of $744
discounted at 7%. See description below............. -- 680
----------- -----------
106,567 224,015
Less current portion...................................... 1,867 2,432
----------- -----------
$ 104,700 $ 221,583
=========== ===========

At December 31, 2001, we had $108.0 million in 11.625 percent senior unsecured
notes due in May 1, 2003, all of which have been redeemed, which resulted in a
gain of $0.9 million in 2002. In November 1997, we issued $115.0 million in
9.375 percent senior unsecured notes due November 1, 2007 ("2007 Notes"), of
which we repurchased $30.0 million. Interest on the 2007 Notes is due May 1 and
November 1 of each year. At December 31, 2002, we were in compliance with all
covenants of the indenture.

In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan
commercial bank, for construction of an oil pipeline. The loan is in two parts,
with the first part in an original principal amount of $6.0 million that bears

S-13

interest payable monthly based on 90-day London Interbank Borrowing Rate
("LIBOR") plus 5 percent with principal payable quarterly for five years. The
second part, in the original principal amount of 4.4 billion Venezuelan Bolivars
("Bolivars") (approximately $6.3 million), bears interest payable monthly based
on a mutually agreed interest rate determined quarterly, or a six-bank average
published by the central bank of Venezuela. The interest rate for the quarter
ending December 31, 2002 was 39.7 percent with a negative effective interest
rate taking into account exchange gains resulting from the devaluation of the
Bolivar during the year. The loans provide for certain limitations on mergers
and sale of assets. The Company has guaranteed the repayment of this loan

On October 1, 2002, Benton-Vinccler, C.A. executed a note and borrowed $15.5
million to fund construction of a gas pipeline and related facilities to deliver
natural gas from the Uracoa field to a PDVSA pipeline. The interest rate for
this loan is LIBOR plus 6 percentage points determined quarterly. The term is
four years with a one year debt service grace period to coincide with our gas
sales and a quarterly amortization of $1.3 million.

Benton-Vinccler's oil and gas pipeline project loans allow the lender to
accelerate repayment if production ceases for a period greater than thirty days.
During the production shut-in which started in December 2002, Benton-Vinccler
was granted a waiver of this provision until February 18, 2003 for a prepayment
of the next two principal obligations aggregating $0.9 million. This prepayment,
while using cash reserves, reduces our net interest expense as the current
interest expense was more than the current interest income earned on the
invested funds. On February 8, 2003, Benton-Vinccler commenced production,
thereby eliminating the need for an additional waiver. A future disruption of
production could trigger the debt acceleration provision again. While no
assurances can be given, we believe Benton-Vinccler would be able to obtain
another waiver.

In 2001, a dispute arose over collection by municipal taxing regimes on the
Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit
resulting in overpayments and underpayments to adjacent municipalities. As
settlement, a portion of future municipal tax payments will be offset by the
municipal tax that was originally overpaid. The present value of the long-term
portion of the settlement liability is $0.7 million at December 31, 2001. The
entire balance was repaid by December 31, 2002.

The principal payment requirements for our long-term debt outstanding at
December 31, 2002 are as follows (in thousands):

2003.......................................................... $ 1,867
2004.......................................................... 7,035
2005.......................................................... 7,035
2006.......................................................... 5,630
2007.......................................................... 85,000
-----------
$ 106,567
===========

LIQUIDITY

We currently have a significant debt obligation payable in November 2007 of $85
million. Our ability to meet our debt obligations and to reduce our level of
debt depends on the successful implementation of our strategic objectives. Our
cash flow from operations complemented with our cash and cash equivalents of
$91.9 million at December 31, 2002, can be invested in other opportunities used
to develop our significant proved undeveloped reserves or used to repurchase our
outstanding debt.

NOTE 4 - COMMITMENTS AND CONTINGENCIES

We have employment contracts with four executive officers which provide for
annual base salaries, eligibility for bonus compensation and various benefits.
The contracts provide for a lump sum payment as a multiple of base salary in the
event of termination of employment without cause. In addition, these contracts
provide for payments as a multiple of base salary and bonus, tax reimbursement
and a continuation of benefits in the event of termination without cause
following a change in control of the Company. By providing one year notice,
these agreements may be terminated by either party on May 31, 2004.

S-14

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 which has been subleased for rents that
approximate our lease costs.

The Company is a defendant in or otherwise involved in litigation incidental to
its business. In the opinion of management, there is no litigation which is
material to the Company.

NOTE 5 - TAXES

TAXES OTHER THAN ON INCOME

Benton-Vinccler pays a municipal tax on operating fee revenues it receives for
production from the South Monagas Unit. The components of taxes other than on
income were (in thousands):

2002 2001 2000
--------- --------- ---------

Venezuelan municipal taxes........................... $ 3,805 $ 4,447 $ 3,164
Severance and production taxes....................... - - 28
Franchise taxes...................................... 139 121 131
Payroll and other taxes.............................. 124 802 1,067
--------- --------- ---------
$ 4,068 $ 5,370 $ 4,390
========= ========= =========

TAXES ON INCOME

The tax effects of significant items comprising our net deferred income taxes as
of December 31, 2002 and 2001 are as follows (in thousands):

2002 2001
----------- -----------

Deferred tax assets:
Operating loss carryforwards............................... $ 19,690 $ 49,000
Difference in basis of property............................ 21,495 19,300
Other...................................................... 2,043 9,100
Valuation allowance........................................ (39,146) (19,700)
----------- -----------
Net deferred tax asset......................................... $ 4,082 $ 57,700
=========== ===========

The valuation allowance increased by $19.4 million as a result of the increase
in the U.S. deferred tax assets related to the net operating loss carryforward.
Realization of deferred tax assets associated with net operating loss
carryforwards is dependent upon generating sufficient taxable income prior to
their expiration. Management believes it is more likely than not that they will
be realized through future taxable income.

The components of income before income taxes, minority interest and
extraordinary items are as follows (in thousands):

2002 2001 2000
----------- ----------- -----------

Income (loss) before income taxes
United States................................... $ 89,455 $ (26,572) $ (9,074)
Foreign......................................... 80,356 33,754 46,150
----------- ----------- -----------
Total....................................... $ 169,811 $ 7,182 $ 37,076
=========== =========== ===========

S-15

The provision (benefit) for income taxes consisted of the following at December
31, (in thousands):

2002 2001 2000
----------- ----------- -----------

Current:
United States........................................ $ 353 $ 1 $ 215
Foreign.............................................. 6,324 6,700 5,925
----------- ----------- -----------
$ 6,677 $ 6,701 $ 6,140
=========== =========== ===========
Deferred:
United States........................................ $ 53,413 $ (42,405) --
Foreign.............................................. 205 6 7,892
----------- ----------- -----------
53,618 (42,399) 7,892
----------- ----------- -----------
$ 60,295 $ (35,698) $ 14,032
=========== =========== ===========

A comparison of the income tax expense (benefit) at the federal statutory rate
to our provision for income taxes is as follows (in thousands):

2002 2001 2000
---------- ---------- ----------

Computed tax expense at the statutory rate................... $ 59,348 $ 4,580 $ 13,451
State income taxes........................................... 353 -- (343)
Effect of foreign source income and rate differentials on
foreign income........................................... (19,373) 1,675 (1,826)
Change in valuation allowance................................ 19,446 (53,413) 2,294
Prior year adjustments....................................... -- 2,304 1,637
Reclass paid-in capital...................................... -- 11,007 --
All other.................................................... 80 215 679
---------- ---------- ----------
Sub-total income tax expense (benefit)....................... 59,854 (33,632) 15,892
Effects of recording equity income of certain affiliated
Companies on an after-tax basis.......................... 441 (2,066) (1,860)
---------- ---------- ----------
Total income tax expense (benefit)........................... $ 60,295 $ (35,698) $ 14,032
========== ========== ==========

Rate differentials for foreign income result from tax rates different from the
U.S. tax rate being applied in foreign jurisdictions and from the effect of
foreign currency devaluation in foreign subsidiaries which use the U.S. dollar
as their functional currency.

At December 31, 2002, we had, for federal income tax purposes, operating loss
carryforwards of approximately $56.3 million, expiring in the years 2011 through
2022.

We do 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 our ongoing business.

NOTE 6 - STOCK OPTION AND STOCK PURCHASE PLANS

In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the
"Stock Purchase Plan") to encourage our directors to acquire a greater
proprietary interest in our company through the ownership of our common stock.
Under the Stock Purchase Plan each non-employee director could elect to receive
shares of our common stock for all or a portion of their fee for serving as a
director. The number of shares issuable is equal to 1.5 times the amount of cash
compensation due the director divided by the fair market value of the common
stock on the scheduled date of payment of the applicable director's fee. The
shares have a restriction upon their sale for one year from the date of
issuance. As of December 31, 2002, 337,850 shares had been issued from the plan.
The Stock Purchase Plan was terminated by the Board of Directors in September
2002.

In July 2001, our shareholders approved the adoption of the 2001 Long Term Stock
Incentive Plan. The 2001 Long Term Stock Incentive Plan provides for grants of
options to purchase up to 1,697,000 shares of our common stock in the form of
Incentive Stock Options and Non-qualified Stock Options to eligible participants
including employees of our company or subsidiaries, directors, consultants and
other key persons. The exercise price of stock options granted under the plan
must be no less than the fair market value of our common stock on the date of
grant. No officer may be granted

S-16

more than 500,000 options during any one fiscal year, as adjusted for any
changes in capitalization, such as stock splits. In the event of a change in
control of our company, all outstanding options become immediately exercisable
to the extent permitted by the plan. All options granted to date vest ratably
over a three-year period from their dates of grant and expire ten years from
grant date.

Since 1989 we have adopted several other stock option plans under which options
to purchase shares of our common stock have been granted to employees, officers,
directors, independent contractors and consultants. Options granted under these
plans have been at prices equal to the fair market value of the stock on the
grant dates. Options granted under the plans are generally exercisable in
varying cumulative periodic installments after one year cannot be exercised more
than ten years after the grant dates. Following the adoption of the 2001 Long
Term Stock Incentive Plan, no options may be granted under any of these plans.

A summary of the status of our stock option plans as of December 31, 2002, 2001
and 2000 and changes during the years ending on those dates is presented below
(shares in thousands):

2002 2001 2000
------------------ ------------------ ------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
PRICE SHARES PRICE SHARES PRICE SHARES
-------- ------- -------- ------ -------- ------

Outstanding at beginning of the year: $ 6.36 6,865 $ 7.74 5,660 $ 7.55 6,300
Options granted 4.84 165 1.65 1,684 2.06 240
Options exercised 2.21 (1,515) -- -- 2.53 (85)
Options cancelled 8.03 (292) 6.43 (479) 4.90 (795)
------- ------ ------
Outstanding at end of the year 7.42 5,223 6.36 6,865 7.74 5,660
======= ====== ======
Exercisable at end of the year 8.49 4,360 8.32 4,800 9.68 4,099
======= ====== ======

Significant option groups outstanding at December 31, 2002 and related weighted
average price and life information follow:

OUTSTANDING EXERCISABLE
---------------------------------------------------------- --------------------------------------
RANGE OF NUMBER WEIGHTED-AVERAGE NUMBER
EXERCISE OUTSTANDING AT REMAINING WEIGHTED-AVERAGE EXERCISABLE AT WEIGHTED-AVERAGE
PRICES DECEMBER 31, 2002 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 2002 EXERCISE PRICE
--------------- ----------------- ----------------- ---------------- ----------------- ----------------

$ 1.55 - $ 2.75 2,475,149 7.70 $ 1.97 1,737,066 $ 2.09
$ 4.89 - $ 7.00 520,333 4.38 5.77 395,333 6.07
$ 7.25 - $11.00 660,633 3.16 8.88 660,633 8.88
$11.50 - $16.50 1,071,665 3.91 13.58 1,071,665 13.58
$17.38 - $24.13 494,833 4.05 21.13 494,833 21.13
----------- ----------
5,222,613 4,359,530
=========== ==========

Of the number outstanding, 1,233,750 options are controlled by the company
through the A. E. Benton settlement. See Note 13 - Related Party Transactions.

In connection with our acquisition of Benton Offshore China Company in December
1996, we 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 our 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 our common stock. All
options were issued upon the acquisition of Benton Offshore China Company and
vested upon issuance. At December 31, 2002, 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 $5.63 to $11.88 which vest over three to four years. At December
31, 2002, a total of 192,500 options issued outside of the plans were both
outstanding and exercisable.

S-17

NOTE 7 - STOCK WARRANTS

The dates the warrants were issued, the expiration dates, the exercise prices
and the number of warrants issued and outstanding at December 31, 2002 were
(warrants in thousands):

WARRANTS
----------------------------
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING
----------- --------------- -------------- -------- -----------

July 1994 July 2004 $ 7.50 150 8
December 1994 December 2004 12.00 50 50
June 1995 June 2007 17.09 125 125
-------- ---------
325 183
======== =========

NOTE 8 - OPERATING SEGMENTS

We regularly allocate resources to and assess the performance of our 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. Revenue from
Venezuela is 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.

YEAR ENDED DECEMBER 31, 2002:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
----------- ------------- ------------ ------------ ------------

Revenues
Oil sales............................... $ 127,015 $ - $ - $ - $ 127,015
Other comprehensive loss: hedge......... (284) - - - (284)
----------- ---------- ------------ --------- ---------
126,731 - - - 126,731
----------- ---------- ------------ --------- ---------
Expenses
Operating expenses...................... 31,457 360 2,133 - 33,950
Depletion, depreciation and
amortization.......................... 23,850 2,483 30 - 26,363
General and administrative.............. 4,310 11,420 774 - 16,504
Bad debt recovery....................... - (3,276) - - (3,276)
Taxes other than on income.............. 3,997 71 - - 4,068
----------- ---------- ------------ --------- ---------
Total expenses.................... 63,614 11,058 2,937 - 77,609
----------- ---------- ------------ --------- ---------
Income (loss) from operations............... 63,117 (11,058) (2,937) - 49,122
Other non-operating income (expense)
Gain on sale of investment.............. - 144,032 (3) - 144,029
Gain on early extinguishment of debt.... - 874 - - 874
Investment earnings and other........... 1,889 1,653 - (1,462) 2,080
Interest expense........................ (4,237) (13,611) - 1,538 (16,310)
Net gain on exchange rates.............. 4,356 197 - - 4,553
Intersegment revenues (expenses)........ 15,156 (15,156) - - -
Equity in income of affiliated
companies............................. - - 165 - 165
----------- ---------- ------------ --------- ---------
17,164 117,989 162 76 135,391
----------- ---------- ------------ --------- ---------
Income (loss) before income taxes........... 80,281 106,931 (2,775) 76 184,513
Income tax expense.......................... 6,453 53,764 2 76 60,295
----------- ---------- ------------ --------- ---------
Operating segment income (loss)............. 73,828 53,167 (2,777) - 124,218
Write-down of oil and gas properties and
impairments............................... - (14,537) - - (14,537)
Minority interest........................... (9,319) - - - (9,319)
----------- ---------- ------------ --------- ---------
Net income (loss)........................... $ 64,509 $ 38,630 $ (2,777) $ - $ 100,362
=========== ========== ============ ========= =========
Total assets................................ $ 209,733 $ 122,355 $ 52,302 $ (49,198) $ 335,192
=========== ========== ============ ========= =========
Additions to properties..................... $ 42,486 $ 738 $ 122 $ - $ 43,346
=========== ========== ============ ========= =========

S-18

YEAR ENDED DECEMBER 31, 2001:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
----------- ------------- ------------ ------------ ------------

Revenues
Oil sales............................... $ 122,386 $ - $ - $ - $ 122,386
----------- ---------- ------------ --------- ---------
Expenses
Operating expenses...................... 42,037 55 667 - 42,759
Depletion, depreciation and
amortization.......................... 22,096 3,408 12 - 25,516
General and administrative.............. 4,151 14,972 949 - 20,072
Taxes other than on income.............. 4,666 704 - - 5,370
----------- ---------- ------------ --------- ---------
Total expenses.................... 72,950 19,139 1,628 - 93,717
----------- ---------- ------------ --------- ---------
Income (loss) from operations............... 49,436 (19,139) (1,628) - 28,669
Other non-operating income (expense):
Investment earnings and other........... 5,995 2,053 60 (5,020) 3,088
Interest expense........................ (7,403) (22,695) - 5,223 (24,875)
Net gain on exchange rates.............. 732 36 - - 768
Intersegment revenues (expenses)........ (14,983) 14,983 - - -
Equity in income of affiliated
companies............................. - - 5,902 - 5,902
----------- ---------- ------------ --------- ---------
(15,659) (5,623) 5,962 203 (15,117)
----------- ---------- ------------ --------- ---------
Income (loss) before income taxes........... 33,777 (24,762) 4,334 203 13,552
Income tax (benefit) expense ............... 6,491 (42,392) - 203 (35,698)
----------- ---------- ------------ --------- ---------
Operating segment income.................... 27,286 17,630 4,334 - 49,250
Write-down of oil and gas properties and
impairments............................... - (468) - - (468)
Minority interest........................... (5,545) - - - (5,545)
----------- ---------- ------------ --------- ---------
Net income.................................. $ 21,741 $ 17,162 $ 4,334 $ - $ 43,237
=========== ========== ============ ========= =========
Total assets................................ $ 167,671 $ 165,254 $ 100,801 $ (85,575) $ 348,151
=========== ========== ============ ========= =========
Additions to properties..................... $ 43,411 $ - $ 31 $ - $ 43,442
=========== ========== ============ ========= =========

YEAR ENDED DECEMBER 31, 2000:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
----------- ------------- ------------ ------------ ------------

Revenues
Oil and natural gas sales............... $ 139,890 $ 394 $ - $ - $ 140,284
----------- ---------- ------------ --------- ---------
139,890 394 - - 140,284
----------- ---------- ------------ --------- ---------
Expenses
Operating expenses...................... 46,727 59 644 - 47,430
Depletion, depreciation and
amortization.......................... 16,285 879 11 - 17,175
General and administrative.............. 3,659 12,014 1,066 - 16,739
Taxes other than on income.............. 3,355 1,048 (13) - 4,390
----------- ---------- ------------- --------- ---------
Total expenses.................... 70,026 14,000 1,708 - 85,734
----------- ---------- ------------ --------- ---------
Income (loss) from operations............... 69,864 (13,606) (1,708) - 54,550
Other non-operating income (expense):
Investment earnings and other........... 1,392 8,986 - (1,819) 8,559
Interest expense........................ (6,131) (24,661) - 1,819 (28,973)
Net gain on exchange rates.............. 298 28 - - 326
Intersegment revenues (expenses)........ (12,226) 12,226 - - -
Equity in income of affiliated
companies............................. - - 5,313 - 5,313
----------- ---------- ------------ --------- ---------
(16,667) (3,421) 5,313 - (14,775)
------------ ----------- ------------ --------- ---------
Income (loss) before income taxes........... 53,197 (17,027) 3,605 - 39,775
Income tax expense ......................... 14,020 12 - - 14,032
----------- ---------- ------------ --------- ---------
Operating segment income (loss)............. 39,177 (17,039) 3,605 - 25,743
Write-down of oil and gas properties and
impairments............................... - (1,346) - - (1,346)
Minority interest........................... (7,869) - - - (7,869)
Extraordinary income on debt repurchase..... - 3,960 - - 3,960
----------- ---------- ------------ --------- ---------
Net income (loss)........................... $ 31,308 $ (14,425) $ 3,605 $ - $ 20,488
=========== ========== ============ ========= =========
Total assets................................ $ 166,462 $ 156,780 $ 78,406 $(115,201) $ 286,447
=========== ========== ============ ========= =========
Additions to properties..................... $ 54,112 $ 3,075 $ 9 $ - $ 57,196
=========== ========== ============ ========= =========

NOTE 9 - RUSSIAN OPERATIONS

GEOILBENT

We own 34 percent of Geoilbent, a Russian limited liability company
formed in 1991 to develop, produce and market crude oil from the North
Gubkinskoye and South Tarasovskoye fields in the West Siberia region of Russia.
Our investment in Geoilbent is accounted for using the equity method. Sales
quantities attributable to Geoilbent for the years ended September 30, 2002,
2001 and 2000 were 6.9 million Bbls, (4.6 million domestic and 2.3 million
export) 5.2 million Bbls, (0.8 million domestic and 4.4 million export) and 4.2
million Bbls, respectively.

S-19

Prices for crude oil for the years ended September 30, 2002, 2001 and 2000
averaged $13.25 ($8.89 domestic and $21.73 export), $19.51 ($13.69 domestic and
$20.48 export) and $18.56 per barrel, respectively. Depletion expense
attributable to Geoilbent for the years ended September 30, 2002, 2001 and 2000
was $3.93, $2.88 and $2.25 per barrel, respectively. Summarized financial
information for Geoilbent follows (in thousands). All amounts represent 100
percent of Geoilbent.

Year ended September 30: 2002 2001 2000
----------- ----------- -----------

Revenues
Oil sales.................................................... $ 91,598 $ 101,159 $ 78,805
----------- ----------- -----------

Expenses
Selling and distribution expenses............................ 6,696 9,876 4,612
Operating expenses........................................... 15,360 11,415 8,959
Depletion, depreciation and amortization..................... 27,168 14,918 9,556
General and administrative................................... 8,335 5,650 3,407
Taxes other than on income................................... 27,657 26,011 18,286
----------- ----------- -----------
85,216 67,870 44,820
----------- ----------- -----------

Income from operations........................................... 6,382 33,289 33,985

Other non-operating income (expense)
Investment earnings and other................................ 381 648 (724)
Interest expense............................................. (4,629) (7,547) (7,438)
Net gain (loss) on exchange rates............................ 2,053 781 (597)
----------- ----------- -----------
(2,195) (6,118) (8,759)
----------- ----------- -----------

Income before income taxes....................................... 4,187 27,171 25,226
Income tax expense............................................... 302 6,751 6,321
----------- ----------- -----------
Net income ...................................................... $ 3,885 $ 20,420 $ 18,905
=========== =========== ===========

AT SEPTEMBER 30:
Current assets................................................... $ 18,785 $ 35,447 $ 30,979
Other assets..................................................... 186,815 187,706 163,332
Current liabilities.............................................. 54,051 60,439 36,567
Other liabilities................................................ 7,500 22,550 38,000
Net equity....................................................... 144,049 140,164 119,744

The European Bank for Reconstruction and Development ("EBRD") and
International Moscow Bank ("IMB") together agreed in 1996 to lend up to $65
million to Geoilbent, based on achieving certain reserve and production
milestones, under parallel reserve-based loan agreements. As of September 30,
2002, the outstanding balance of the loan with EBRD was $22 million and the IMB
portion was $0.6 million which was repaid in November 2002. By agreement dated
September 23, 2002, the loan agreement with EBRD was restructured into a
revolving credit agreement, with up to $50.0 million available, including the
$22 million already outstanding. The interest rate for the restructured loan is
six-month LIBOR plus 4.75 percent, with additional interest up to 3 percent
during the term portion of the loan based upon Geoilbent's net income. Principal
payments are due in six equal semiannual installments beginning January 27,
2004. The restructured loan agreement grants EBRD a security interest in the
assets of Geoilbent and requires that Geoilbent meet certain financial ratios
and covenants, including a minimum current ratio. As of September 30, 2002,
Geoilbent was not in compliance with the current 1:1 ratio requirement, but had
received a waiver from EBRD through the quarters ended September 30, 2002. The
loan agreement also provides for certain limitations on liens, additional
indebtedness, certain investments, capital expenditures, dividends, mergers and
sales of assets. In addition, the Company and Minley, have pledged their
ownership interests in Geoilbent as security for the debt, and agreed to support
Geoilbent in its obligations under the loan agreement, including providing
technical and managerial personnel and resources to develop its fields. Under
these agreements, the Company and Minley are each jointly and severally liable
to EBRD for any losses, damages, liabilities, costs, expenses and other amounts
suffered or sustained arising out of any breach by the other of its support
obligations. As available, proceeds from the restructured loan will be used to
reduce payables and to develop the South Tarasovskoye Field.

S-20

The waiver from EBRD of the current ratio requirement expires March 31,
2003. On March 12, 2003 Geoilbent drew $8.0 million under the loan to reduce
payables, there can be no assurance that the draw will be adequate to permit
Geoilbent to meet the ratio requirement. If Geoilbent fails to meet the ratio
requirements for two consecutive quarters it will result in an event of default
whereby EBRD may, at its option, demand payment of the outstanding principal and
interest. In addition, the restructured loan agreement requires that Geoilbent
implement a new management information system by May 1, 2003. Geoilbent will be
unable to timely satisfy this requirement which also results in an event of
default whereby EBRD may, at its option, demand payment of the outstanding
principal and interest.

At September 30, 2002, and September 30, 2001, the current liabilities
of Geoilbent exceeded its current assets by $35.3 million and $25.7 million,
respectively. Included in current liabilities as of September 30, 2002 are loans
repayable to EBRD ($22.0 million) and IMB ($0.6 million). This debt has been
classified as current because Geoilbent will not be able to implement a new
management information system as required by the EBRD loan facility. As a result
of this situation, Geoilbent's independent accountants have indicated in their
report that substantial doubt exists regarding Geoilbent's ability to meet its
debts as they come due. While no assurance can be given, the Company believes
these covenant defaults are temporary and does not result in an other than
temporary decline in the Company's investment in Geoilbent or will cause EBRD to
declare a default after considering Geoilbent's historical net income, cash flow
from operating activities and other matters.

Because of Geoilbent's significant working capital deficit, a
substantial portion of its cash flow must be utilized to reduce accounts and
taxes payable. Additionally, in order to maintain or increase proved oil and gas
reserves, Geoilbent must make substantial capital expenditures in 2003.
Geoilbent's net cash provided by operating activities is dependent on the level
of oil prices, which are historically volatile and are significantly impacted by
the proportion of production that Geoilbent can sell on the export market.
Historically, Geoilbent has supplemented its cash flow from operations with
additional borrowings or equity capital and may need to continue to do so.
Should oil prices decline for a prolonged period or should Geoilbent not have
access to additional capital, Geoilbent would need to reduce its capital
expenditures, which could limit its ability to maintain or increase production
and, in turn, meet its debt service requirements. Asset sales and financing are
restricted under the terms of the EBRD loan.

Geoilbent management plans to further address the working capital
deficit by reducing certain capital expenditures and funding its 2003 debt
service and planned capital expenditures with cash flows from existing producing
properties and its development drilling program. At December 31, 2002, Geoilbent
had accounts payable outstanding of $12.2 million of which approximately $5.9
million was 90 days or more past due. The amounts outstanding were primarily to
contractors and vendors for drilling and construction services. Under Russian
law, creditors, to whom payments are 90 days or more past due, can force a
company into involuntary bankruptcy. Geoilbent's financial statements do not
include any adjustments that might result if Geoilbent were unable to continue
as a going concern.

As of September 30, 2002, the Geoilbent ($2.5 million from Harvest and
$5.0 million from Minley) shareholders had provided Geoilbent with subordinated
loans totaling $7.5 million. These loans are unsecured and repayable commencing
in January 2004. Our interest rate is based on LIBOR up to January 2004, and
rises from 8 to 12 percent thereafter. There can be no assurance that Geoilbent
will have the ability to repay the loan made by the Company when due.

ARCTIC GAS COMPANY

In April 1998, we signed an agreement to earn a 40 percent equity
interest in Arctic Gas Company, formerly Severneftegaz. 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 794,972 acres within and adjacent to the Urengoy Field,
Russia's largest producing natural gas field. Under the terms of a Cooperation
Agreement between us and Arctic Gas, we will earn a 40 percent equity interest
in exchange for providing or arranging for a credit facility of up to $100
million for the project, the terms and timing of which were finalized in
February 2002. We received voting shares representing 40 percent 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. From December 1998 through December 31,
2001, we purchased shares representing an additional 28 percent equity interest
not subject to any sale or transfer restrictions. On April 12, 2002, we
concluded the Arctic Gas

S-21

Sale and transferred our 68 percent equity interest to the buyer. The equity
earnings of Arctic Gas have historically been based on a calendar year ended
September 30. The fourth quarter of 2001, the first quarter of 2002 and the
first twelve days of April have been included in the results for 2002.

We account for our interest in Arctic Gas using the equity method due
to the significant influence we exercise over the operating and financial
policies of Arctic Gas. Our weighted-average equity interest, not subject to any
sale or transfer restrictions for the years ended December 31, 2002, 2001 and
2000 was 49 percent, 39 percent and 29 percent, respectively. We recorded as our
share in the losses of Arctic Gas $1.5 million, $1.1 million and $0.7 million
for the period ended April 12, 2002 and September 30, 2001, and 2000,
respectively. Certain provisions of Russian corporate law would effectively
require minority shareholder consent to enter into new agreements between us and
Arctic Gas, or change 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. Arctic Gas began
selling oil in June 2000. Summarized financial information for Arctic Gas
follows (in thousands). All amounts represent 100 percent of Arctic Gas.

S-22

NOTE 10 - VENEZUELA OPERATIONS

On July 31, 1992, we and our 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, PDVSA.
The operating service agreement covers the Uracoa, Bombal and Tucupita Fields
that comprise the South Monagas Unit . Under the terms of the operating service
agreement, Benton-Vinccler, a Venezuelan corporation owned 80 percent by us and
20 percent by Vinccler, is a contractor for PDVSA and 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.
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.

On September 19, 2002, Benton-Vinccler and PDVSA signed an amendment to the
operating service agreement, providing for the delivery of up to 198 Bcf of
natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales are
expected to commence at a rate of 40 to 50 MMcf of natural gas per day in the
fourth quarter of 2003 and gradually increase up to 70 MMcfpd in 12 to 18 months
from the initial sale. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5
million barrels of oil at $7.00 per barrel beginning with our first gas sale.
Initial gas production will come from Uracoa, which allows us to more
efficiently manage the reservoir and eliminate the restrictions on producing oil
wells with high gas to oil ratios. The gas reserves in Bombal will be used to
meet the future terms of the gas contract in 2005 or 2006.

The Venezuelan government maintains full ownership of all hydrocarbons in the
fields.

We drilled eleven oil and two water injection wells in 2002.

NOTE 11 - UNITED STATES OPERATIONS

We had a 35 percent working interest in the Lakeside Exploration Prospect,
Cameron Parish, Louisiana. In September 2002, we determined that the Claude
Boudreaux #1 exploratory well was not prospective for hydrocarbons and assigned
our entire interest in the Lakeside Exploration Prospect to a third party. We
recognized $1.1 million impairment in the three months ended September 30, 2002.

We acquired a 100 percent interest in three California State offshore oil and
gas leases ("California Leases") and a parcel of onshore property from Molino
Energy Company, LLC. We impaired 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. The Company has determined
that it will not pursue further development of the California Leases, and will
plug and abandon the previously drilled exploratory well, and undertake any
required lease and land reclamation. It is believed that these costs will not be
material.

NOTE 12 - CHINA OPERATIONS

In December 1996, we acquired Crestone Energy Corporation, 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 1.25 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 another company. The territorial
dispute has lasted for many years, and there has been limited exploration and no
development activity in the area under dispute. As part of our review of company
assets, we conducted a third-party evaluation of the WAB-21 area. Through that
evaluation and our own assessment we recorded a $13.4 million impairment charge
in the second quarter of 2002. WAB-21 represents the $2.9 million excluded from
the full cost pool as reflected on our December 31, 2002 balance sheet.

S-23

NOTE 13 - RELATED PARTY TRANSACTIONS

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 our 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 with Mr. Benton pursuant to which we
retained Mr. Benton under a consulting agreement to perform certain services for
us. In addition, the consulting agreement provided Mr. Benton with incentive
bonuses tied to our net cash receipts from the sale of our interests in Arctic
Gas and Geoilbent. We paid Mr. Benton a total of $536,545 from February 2000
through May 2001 for services performed under the consulting agreement, and in
June 2002, we made an estimated incentive bonus payment to Mr. Benton of $1.5
million in connection with the Arctic Gas Sale which we recorded as a reduction
of the gain on the Arctic Gas Sale.

On May 11, 2001, Mr. Benton and the Company entered into a settlement and
release agreement under which the consulting agreement was terminated as to
future services and Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the repayment of our loans to him. In March
2002, Mr. Benton filed a plan of reorganization in his bankruptcy case which
incorporated the terms of the settlement agreement. On July 31, 2002, the
bankruptcy court confirmed the plan of reorganization, and the order to become
final on August 10, 2002. As of that date, Mr. Benton's indebtedness was about
$6.7 million for which we provided a full reserve. On August 14, 2002, we
exercised our rights with respect to 600,000 shares of stock in the Company
pledged to repayment of the loan and took the shares into the Company as
treasury stock. Based on a $3.56 closing price for the stock on that date, the
value of the shares was $2.1 million. Also, in September 2002, we received a
payment of about $1.1 million as a partial distribution from Mr. Benton's
debtor-in-possession account. Finally, under the terms of the settlement
agreement, we have retained about $0.1 million from the Arctic Gas bonus payment
to Mr. Benton for a total recovery of $3.3 million. We continue to accrue
interest and provide a reserve on the remaining amount due. About $960,000
remains in the debtor-in-possession account which Mr. Benton has withheld to
cover expenses and estimated tax liability for the 600,000 shares of stock we
acquired from Mr. Benton. We are due the balance of this account as the expenses
and tax liabilities are finally determined. We also hold the rights to direct
the exercise of Mr. Benton's stock options.

Mr. Benton and the Company disagree over Mr. Benton's remaining obligations to
us under the settlement agreement and plan of reorganization. In addition, Mr.
Benton is claiming that he is due significant additional amounts with respect to
the incentive bonus associated with the Arctic Gas Sale. Mr. Benton and the
Company have agreed to submit their dispute to binding arbitration. While the
outcome of arbitration cannot be predicted, we believe that we have a
substantial basis for our positions and intend to vigorously pursue them.

NOTE 14 - EARNINGS PER SHARE

Basic earnings per common share ("EPS") is computed by dividing income available
to common stockholders by the weighted-average number of common shares
outstanding for the period. The weighted average number of common shares
outstanding for computing basic EPS was 34.6 million, 34.0 million and 30.7
million for the years ended December 31, 2002, 2001 and 2000, respectively.
Diluted EPS reflects the potential dilution that could occur if securities or
other contracts to issue common stock were exercised or converted into common
stock. The weighted average number of common shares outstanding for computing
diluted EPS, including dilutive stock options, was 36.1 million, 34.0 million
and 30.9 million for the years ended December 31, 2002, 2001 and 2000,
respectively.

An aggregate of 3.5 million options and warrants were excluded from the earnings
per share calculations because their exercise price exceeded the average share
price during the year ended December 31, 2002. For the years ended December 31,
2001 and 2000, 6.7 million and 5.6 million options and warrants, respectively,
were excluded from the earnings per share calculations because they were
anti-dilutive.

NOTE 15 - SUBSEQUENT EVENT

Benton-Vinccler has hedged a portion of its 2003 oil sales by purchasing a WTI
crude oil "put" to protect its 2003 cash flow. The put is for 10,000 barrels of
oil per day for the period of March 1, 2003 through December 31, 2003. Due to
the pricing structure for our Venezuela oil, the put has the economic effect of
hedging approximately 20,000 Bopd. The put costing $2.50 per barrel, or
approximately $7.7 million, has a strike price of $30.00 per barrel.

S-24

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data is as follows:

QUARTER ENDED
---------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
----------- ----------- ------------ -----------
(amounts in thousands, except per share data)

YEAR ENDED DECEMBER 31, 2002
Revenues......................................... $ 27,247 $ 33,022 $ 38,841 $ 27,621
Expenses......................................... (18,720) (35,747) (17,914) (19,765)
Non-operating income (expense)................... (3,948) 142,940 (818) (2,948)
Income (loss) from consolidated companies before
income taxes and minority interests........... 4,579 140,215 20,109 4,908
Income tax expense (benefit)..................... 1,801 59,692 6,612 (7,810)
----------- ----------- ----------- -----------
Income (loss) before minority interests.......... 2,778 80,523 13,497 12,718
Minority interests............................ 1,380 2,031 2,590 3,318
----------- ----------- ----------- -----------
Income (loss) from consolidated companies........ 1,398 78,492 10,907 9,400
Equity in earnings (loss) of affiliated
companies...................................... 87 (2,172) 1,209 1,041
Net income (loss)................................ $ 1,485 $ 76,320 $ 12,116 $ 10,441
Other comprehensive loss......................... -- -- (658) --
----------- ----------- ----------- -----------
Total comprehensive income....................... $ 1,485 $ 76,320 $ 11,458 $ 9,791
=========== =========== =========== ===========
Net income (loss) per common share:
Basic ........................................ $ 0.04 $ 2.20 $ 0.35 $ 0.30
=========== =========== =========== ===========
Diluted....................................... $ 0.04 $ 2.10 $ 0.33 $ 0.28
=========== =========== =========== ===========

QUARTER ENDED
---------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
----------- ----------- ------------ -----------
(amounts in thousands, except per share data)

YEAR ENDED DECEMBER 31, 2001
Revenues......................................... $ 34,338 $ 32,844 $ 31,370 $ 23,834
Expenses......................................... (24,674) (24,493) (22,345) (22,673)
Non-operating expense............................ (5,304) (5,152) (5,119) (5,444)
Income (loss) from consolidated companies before
income taxes and minority interests........... 4,360 3,199 3,906 (4,283)
Income tax expense (benefit)..................... 3,196 3,881 3,510 (46,285)
----------- ----------- ----------- -----------
Income (loss) before minority interests.......... 1,164 (682) 396 42,002
Minority interests............................ 1,293 1,541 1,523 1,188
----------- ----------- ----------- -----------
Income (loss) from consolidated companies........ (129) (2,223) (1,127) 40,814
Equity in earnings (loss) of affiliated
companies...................................... 2,414 1,061 2,859 (432)
Net income (loss)................................ $ 2,285 $ (1,162) $ 1,732 $ 40,382
=========== =========== =========== ===========
Net income (loss) per common share:
Basic and Diluted............................. $ 0.07 $ (0.03) $ 0.05 $ 1.19
=========== =========== =========== ===========

In the second quarter of 2002, we recognized in non-operating income, the $140.2
million pre-tax gain on the Arctic Gas Sale, and in expense, the write-down of
capitalized costs of $13.4 million associated with our WAB-21 offshore China
concession.

In the fourth quarter of 2001, we recognized a $50.4 million tax benefit related
to the expected utilization by the Arctic Gas Sale in 2002.

S-25

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL 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 our oil and natural gas exploration and
production activities. 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 our 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.

TABLE I - TOTAL COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION,
EXPLORATION AND DEVELOPMENT ACTIVITIES (IN THOUSANDS):

UNITED STATES
VENEZUELA CHINA AND OTHER TOTAL
--------- --------- ------------- ---------

YEAR ENDED DECEMBER 31, 2002
Development costs $ 49,163 $ 120 $ 577 $ 49,860
Exploration costs 794 (149) 88 733
--------- --------- --------- ---------
$ 49,957 $ (29) $ 665 $ 50,593
========= ========= ========= =========

YEAR ENDED DECEMBER 31, 2001
Development costs $ 35,194 $ 77 $ 28 $ 35,299
Exploration costs 7,694 - 909 8,603
--------- --------- --------- ---------
$ 42,888 $ 77 $ 937 $ 43,902
========= ========= ========= =========

YEAR ENDED DECEMBER 31, 2000
Acquisition costs $ - $ - $ 170 $ 170
Development costs 47,604 - - 47,604
Exploration costs 94 84 2,470 2,648
--------- --------- --------- ---------
$ 47,698 $ 84 $ 2,640 $ 50,422
========= ========= ========= =========

TABLE II - CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS):

UNITED STATES
VENEZUELA CHINA AND OTHER TOTAL
--------- --------- ------------- ---------

DECEMBER 31, 2002
Proved property costs $ 519,175 $ 26,210 $ 21,030 $ 566,415
Costs excluded from amortization -- 2,900 -- 2,900
Oilfield inventories 7,286 -- -- 7,286
Less accumulated depletion and impairment (386,824) (26,210) (20,764) (433,798)
--------- --------- --------- ---------
$ 139,637 $ 2,900 $ 266 $ 142,803
========= ========= ========= =========

DECEMBER 31, 2001
Proved property costs $ 469,218 $ 12,892 $ 19,813 $ 501,923
Costs excluded from amortization - 16,248 560 16,808
Oilfield inventories 15,219 - - 15,219
Less accumulated depletion and impairment (361,313) (12,892) (19,544) (393,749)
--------- --------- --------- ---------
$ 123,124 $ 16,248 $ 829 $ 140,201
========= ========= ========= =========

DECEMBER 31, 2000
Proved property costs $ 426,330 $ 12,879 $ 19,362 $ 458,571
Costs excluded from amortization - 16,183 451 16,634
Oilfield inventories 15,343 - - 15,343
Less accumulated depletion and impairment (339,542) (12,879) (19,090) (371,511)
--------- --------- --------- ---------
$ 102,131 $ 16,183 $ 723 $ 119,037
========= ========= ========= =========

S-26

TABLE III - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS):

UNITED STATES
VENEZUELA CHINA AND OTHER TOTAL
--------- --------- ------------- ---------

YEAR ENDED DECEMBER 31, 2002
Oil sales $ 126,731 $ -- $ -- $ 126,731
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income 31,608 2,493 -- 34,101
Write-down of oil and gas properties
and impairments -- 13,371 1,166 14,537
Depletion 24,941 -- -- 24,941
Income tax expense 4,715 3 -- 4,718
--------- --------- --------- ---------
Total expenses 61,264 15,867 1,166 78,297
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities $ 65,467 $ (15,867) $ (1,166) $ 48,434
========= ========= ========= =========

YEAR ENDED DECEMBER 31, 2001
Oil sales $ 122,386 $ -- $ -- $ 122,386
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income 42,212 -- 722 42,934
Write-down of oil and gas properties
and impairments - 13 455 468
Depletion 22,119 -- -- 22,119
Income tax expense 11,156 -- 13 11,169
--------- --------- --------- ---------
Total expenses 75,487 13 1,190 76,690
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities $ 46,899 $ (13) $ (1,190) $ 45,696
========= ========= ========= =========

YEAR ENDED DECEMBER 31, 2000
Oil and natural gas sales $ 139,890 $ -- $ 394 $ 140,284
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income 46,879 -- 731 47,610
Write-down of oil and gas properties
and impairments -- 8 1,338 1,346
Depletion 15,331 -- 45 15,376
Income tax expense 20,398 -- 12 20,410
--------- --------- --------- ---------
Total expenses 82,608 8 2,126 84,742
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities $ 57,282 $ (8) $ (1,732) $ 55,542
========= ========= ========= =========

TABLE IV - QUANTITIES OF OIL AND NATURAL 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. Venezuelan reserves include production
projected through the end of the operating service agreement in July 2012.

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 we consider 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 or for which transportation and/or marketing contracts are not in
place.

Proved Developed Reserves are reserves which can be expected to be recovered
through existing wells with existing equipment and existing 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

S-27

existing wells which are expected to be produced in the predictable future,
where the cost of making such oil and natural 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.

Changes in previous estimates of proved reserves result from new information
obtained from production history and changes in economic factors.

The evaluations of the oil and natural gas reserves as of December 31, 2002,
2001 and 2000 were prepared by Ryder Scott Company L.P., independent petroleum
engineers.

The tables shown below represent our interests in the United Sates and Venezuela
in each of the years. In addition to these reserves is our 34 percent interest
in Geoilbent which combined with our United States and Venezuela crude oil,
condensate and natural gas liquids reserves, represent our net interest in all
reserves as of December 31, 2002.

S-28

MINORITY
UNITED INTEREST IN
STATES VENEZUELA VENEZUELA NET TOTAL
--------- --------- ----------- ---------

PROVED RESERVES-CRUDE OIL, CONDENSATE,
AND NATURAL GAS LIQUIDS (MBbls)
YEAR ENDED DECEMBER 31, 2002
Proved reserves beginning of the year.. -- 104,514 (20,903) 83,611
Revisions of previous estimates.... -- 362 (72) 290
Extensions, discoveries and
improved recovery................ -- -- -- --
Production......................... -- (9,708) 1,942 (7,766)
Sales of reserves in place......... -- -- -- --
--------- --------- --------- ---------
Proved reserves at end of the year..... -- 95,168 (19,033) 76,135
========= ========= ========= =========

Russia - Geoilbent (34%) Proved
reserves at end of the year.......... 24,781
=========

YEAR ENDED DECEMBER 31, 2001
Proved reserves beginning of the year.. -- 123,039 (24,608) 98,431
Revisions of previous estimates.... -- (8,747) 1,749 (6,998)
Extensions, discoveries and
improved recovery................ -- -- -- --
Production......................... -- (9,778) 1,956 (7,822)
Sales of reserves in place......... -- -- -- --
--------- --------- --------- ---------
Proved reserves at end of the year..... -- 104,514 (20,903) 83,611
========= ========= ========= =========

Russia - Arctic Gas (39%) Proved
reserves at end of the year.......... 20,964
=========
Russia - Geoilbent (34%) Proved
reserves at end of the year.......... 29,668
=========

YEAR ENDED DECEMBER 31, 2000
Proved reserves at beginning of the
year................................. -- 134,961 (26,992) 107,969
Revisions of previous estimates.... -- (8,826) 1,765 (7,061)
Purchases of reserves in place..... 15 -- -- 15
Extensions, discoveries and
improved recovery................ -- 6,268 (1,254) 5,014
Production......................... (7) (9,364) 1,873 (7,498)
Sales of reserves in place......... (8) -- -- (8)
--------- --------- --------- ---------
Proved reserves at end of the year..... -- 123,039 (24,608) 98,431
========= ========= ========= =========

Russia - Arctic Gas (29%) Proved
reserves at end of the year.......... 15,821
=========
Russia - Geoilbent (34%) Proved
reserves at end of the year.......... 32,614
=========

PROVED DEVELOPED RESERVES AT:
December 31, 2002...................... -- 53,833 (10,767) 43,066
December 31, 2001...................... -- 51,465 (10,293) 41,172
December 31, 2000...................... -- 67,217 (13,443) 53,774

Russia - Arctic Gas Proved reserves
at end of the year
2001 (39%)............................. 2,483
2000 (29%)............................. 2,325

Russia - Geoilbent (34%) Proved
reserves at end of the year
2002................................... 11,840
2001................................... 15,658
2000................................... 14,913

PROVED RESERVES-NATURAL GAS (MMcf)
YEAR ENDED DECEMBER 31, 2002
Proved reserves beginning of the year.. -- -- -- --
Revisions of previous estimates.... -- -- -- --
Extensions, discoveries and
improved recovery................ -- 198,000 (39,600) 158,400
Sales of reserves in place......... -- -- -- --
--------- --------- --------- ---------
Proved reserves end of the year........ 198,000 (39,600) 158,400
========= ========= ========= =========

Russia - Arctic Gas (39%) Proved
reserves - December 31, 2001......... 208,010
=========
Russia - Arctic Gas (39%)
Proved reserves - December 31, 2000.. 152,496
=========

PROVED DEVELOPED RESERVES AT:
December 31, 2002...................... -- 105,000 (21,000) 84,000

Russia - Arctic Gas
2001 (39%)............................. 21,292
2000 (29%)............................. 17,801

S-29

TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO
PROVED OIL AND NATURAL 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 we caution 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.

The tables shown below represent our interest Venezuela in each of the years. In
addition to these reserves is our 34 percent interest in Geoilbent and our
Arctic Gas interest of 39% and 29% at December 31, 2001 and 2000, respectively.
Which combined with our Venezuela crude oil, condensate and natural gas liquids
reserves represent our net interest in all reserves as of December 31, 2002.
Geoilbent's Russian domestic crude oil price declined significantly for the
period from September 30, 2002 until December 31, 2002. The standardized measure
of discounted future net cash flows declined from $92.9 million to $41.5
million. There was a $5.05 per barrel decline in the value of a barrel between
these two periods. The reserves in place and development cost structure were
approximately the same. The lower prices at December 31, 2002 were offset by
lower royalties, production taxes, export fees and income taxes. The Russian
domestic crude oil price declined from approximately $9.50 to $5.00 per barrel
by December 31. While world crude oil prices and Russian export prices increased
from approximately $20 to $29. Geoilbent sells approximately 66 percent of its
crude oil sales into the Russian domestic market. Geoilbent's production is
currently limited to shipments on the Transneft crude oil pipeline system. This
system suffers from winter export limitations. Geoilbent reports its
standardized measure of discounted future net cash flows at September 30. The
Company reports the results of Ryder Scott Company L.P. independent engineering
evaluation at December 31 to provide comparability with its Venezuelan reserves.
Geoilbent's 34 percent interest declined by $51.4 million as measured by the
December 31, 2002 year-end weighted average price. We do not believe that the
year-end prices are indicative of the value of Geoilbent. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.

MINORITY
INTEREST IN
VENEZUELA VENEZUELA NET TOTAL
----------- ----------- -----------
(amounts in thousands)

DECEMBER 31, 2002
Future cash inflow $ 1,510,346 $ (302,069) $ 1,208,277
Future production costs (400,694) 80,139 (320,555)
Future development costs (192,671) 38,534 (154,137)
----------- ----------- -----------
Future net revenue before income taxes 916,981 (183,396) 733,585
10% annual discount for estimated timing
of cash flows (315,376) 63,075 (252,301)
----------- ----------- -----------
Discounted future net cash flows before
income taxes 601,605 (120,321) 481,284
Future income taxes, discounted at 10%
per annum (204,356) 40,871 (163,485)
----------- ----------- -----------
Standardized measure of discounted future
net cash flows $ 397,249 $ (79,450) $ 317,799
=========== =========== ===========

Russia - Geoilbent (34%) $ 45,395
===========

S-30

DECEMBER 31, 2001
Future cash flows $ 1,030,404 $ (206,081) $ 824,323
Future production costs (558,431) 111,686 (446,745)
Future development costs (142,006) 28,401 (113,605)
----------- ----------- -----------
Future net revenue before income taxes 329,967 (65,994) 263,973
10% annual discount for estimated timing
of cash flows (109,704) 21,941 (87,763)
----------- ----------- -----------
Discounted future net cash flows before
income taxes 220,263 (44,053) 176,210
Future income taxes, discounted at 10%
per annum (16,103) 3,221 (12,882)
----------- ----------- -----------
Standardized measure of discounted future
net cash flows $ 204,160 $ (40,832) $ 163,328
=========== =========== ===========

Russia - Arctic Gas (29%) $ 82,205
===========
Russia - Geoilbent (34%) $ 70,648
===========

DECEMBER 31, 2000
Future cash inflow $ 1,505,870 $ (301,174) $ 1,204,696
Future production costs (618,870) 123,774 (495,096)
Future development costs (166,039) 33,208 (132,831)
----------- ----------- -----------
Future net revenue before income taxes 720,961 (144,192) 576,769
10% annual discount for estimated timing
of cash flows (260,381) 52,076 (208,305)
----------- ----------- -----------
Discounted future net cash flows before
income taxes 460,580 (92,116) 368,464
Future income taxes, discounted at 10%
per annum (104,894) 20,979 (83,915)
----------- ----------- -----------
Standardized measure of discounted future
net cash flows $ 355,686 $ (71,137) $ 284,549
=========== =========== ===========

Russia - Arctic Gas (29%) $ 56,880
===========
Russia - Geoilbent (34%) $ 114,725
===========

TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES

NET VENEZUELA
-----------------------------------
2002 2001 2000
--------- --------- ---------
(AMOUNTS IN THOUSANDS)

Present Value at January 1 $ 163,328 $ 284,549 $ 380,865
Sales of oil and natural gas, net of related costs (76,098) (64,139) (58,913)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs 310,043 (141,429) (124,402)
Quantities 611 (26,198) (26,494)
Extensions, discoveries and improved recovery, net of future costs 89,670 -- 16,429
Accretion of discount 17,621 36,846 52,135
Net change in income taxes (150,603) 71,033 56,567
Development costs incurred 40,532 23,768 36,210
Changes in timing and other (77,305) (21,102) (47,848)
--------- --------- ---------
Present Value at December 31 $ 317,799 $ 163,328 $ 284,549
========= ========= =========

S-31

ADDITIONAL SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING
ACTIVITIES (UNAUDITED) FOR RUSSIA EQUITY AFFILIATES AS OF SEPTEMBER 30, THEIR
FISCAL YEAR END.

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 our oil and natural gas exploration and
production activities. 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 our 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.

Geoilbent (34 percent ownership by us) and Arctic Gas (39 percent and 29 percent
ownership not subject to certain sale and transfer restrictions at December 31,
2002 and 2001, until Arctic Gas was sold on April 12, 2002, 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 natural gas producing activities in Russia reflect the years ended
September 30, 2002, 2001, and 2000.

TABLE I - TOTAL COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION
AND DEVELOPMENT ACTIVITIES (IN THOUSANDS):

TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------

YEAR ENDED SEPTEMBER 30, 2002
Development costs $ -- $ 8,501 $ 8,501
Exploration costs 16,156 498 16,654
--------- --------- ---------
$ 16,156 $ 8,999 $ 25,155
========= ========= =========

YEAR ENDED SEPTEMBER 30, 2001
Development costs $ -- $ 11,418 $ 11,418
Exploration costs 8,136 2,074 10,210
--------- --------- ---------
$ 8,136 $ 13,492 $ 21,628
========= ========= =========

YEAR ENDED SEPTEMBER 30, 2000
Development costs $ -- $ 13,290 $ 13,290
Exploration costs 4,206 279 4,485
--------- --------- ---------
$ 4,206 $ 13,569 $ 17,775
========= ========= =========

TABLE II - CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS):

TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------

SEPTEMBER 30, 2002
Proved property costs $ -- $ 94,404 $ 94,404
Costs excluded from amortization -- 272 272
Oilfield inventories -- 2,348 2,348
Less accumulated depletion and impairment -- (31,440) (31,440)
--------- --------- ---------
$ -- $ 65,584 $ 65,584
========= ========= =========

SEPTEMBER 30, 2001
Proved property costs $ 5,786 $ 85,677 $ 91,463
Costs excluded from amortization 11,549 -- 11,549
Oilfield inventories 175 4,357 4,532
Less accumulated depletion and impairment (389) (22,203) (22,592)
--------- --------- ---------
$ 17,121 $ 67,831 $ 84,952
========= ========= =========

SEPTEMBER 30, 2000
Proved property costs $ 12,901 $ 72,184 $ 85,085
Costs excluded from amortization 6,536 -- 6,536
Oilfield inventories -- 2,705 2,705
Less accumulated depletion and impairment (78) (17,130) (17,208)
--------- --------- ---------
$ 19,359 $ 57,759 $ 77,118
========= ========= =========

S-32

TABLE III - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS):

TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------

YEAR ENDED DECEMBER 31, 2002
Oil sales $ 3,554 $ 31,039 $ 34,593
Expenses:
Operating, selling and distribution expenses and taxes
other than on income 3,102 16,902 20,004
Depletion 139 9,237 9,376
Income tax expense 19 1,955 1,974
--------- --------- ---------
Total expenses 3,260 28,094 31,354
--------- --------- ---------
Results of operations from oil and natural gas
producing activities $ 294 $ 2,945 $ 3,239
========= ========= =========

YEAR ENDED DECEMBER 31, 2001
Oil sales $ 4,016 $ 34,261 $ 38,277
Expenses:
Operating, selling and distribution expenses and taxes
other than on income 3,381 16,083 19,464
Depletion 311 5,072 5,383
Income tax expense 80 3,742 3,822
--------- --------- ---------
Total expenses 3,772 24,897 28,669
--------- --------- ---------
Results of operations from oil and natural gas
producing activities $ 244 $ 9,364 $ 9,608
========= ========= =========

YEAR ENDED DECEMBER 31, 2000
Oil sales $ 889 $ 26,716 $ 27,605
Expenses:
Operating, selling and distribution expenses and taxes
other than on income 604 10,831 11,435
Depletion 78 3,249 3,327
Income tax expense 54 3,306 3,360
--------- --------- ---------
Total expenses 736 17,386 18,122
--------- --------- ---------
Results of operations from oil and natural gas
producing activities $ 153 $ 9,330 $ 9,483
========= ========= =========

TABLE IV - QUANTITIES OF OIL AND NATURAL 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. Geoilbent and Arctic Gas oil and gas fields are situated on land
belonging to the Government of the Russian Federation. Each obtained licenses
from the local authorities and pays unified production taxes to explore and
produce oil and gas from these fields. Geoilbent's licenses will expire in
September 2018 the license expiration for the North Gubkinskoye field, and in
March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the
Russian Federal Law 20-FZ, dated January 2, 2000, the license may be extended
over the economic life of the lease at Geoilbent's option. Geoilbent intends to
extend such licenses for properties that are expected to produce subsequent to
their expiry dates. Estimates of proved reserves extending past the license
expiration represent approximately 5 percent of total proved reserves. Arctic
Gas had licenses to develop the Samburg and Yevo-Yakhinskiy fields in western
Siberia. Arctic Gas was sold on April 12, 2002.

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 we consider 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 or for which transportation and/or marketing contracts are not in
place.

S-33

Proved Developed Reserves are reserves which can be expected to be recovered
through existing wells with existing equipment and existing 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 natural 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.

Changes in previous estimates of proved reserves result from new information
obtained from production history and changes in economic factors.

TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------

PROVED RESERVES-CRUDE OIL, CONDENSATE,
AND NATURAL GAS LIQUIDS (MBbls)

YEAR ENDED SEPTEMBER 30, 2002
Proved reserves beginning of the year 20,965 29,668 50,633
Revisions of previous estimates -- (3,455) (3,455)
Extensions, discoveries and improved recovery -- 1,493 1,493
Production (89) (2,350) (2,439)
Sales of reserves in place (20,876) -- (20,876)
--------- --------- ---------
Proved reserves at end of the year -- 25,356 25,356
========= ========= =========

YEAR ENDED SEPTEMBER 30, 2001
Proved reserves beginning of the year 15,821 32,614 48,435
Revisions of previous estimates 5,327 (5,594) (267)
Extensions, discoveries and improved recovery -- 4,411 4,411
Production (183) (1,763) (1,946)
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves at end of the year 20,965 29,668 50,633
========= ========= =========

YEAR ENDED SEPTEMBER 30, 2000
Proved reserves beginning of the year 3,715 36,414 40,129
Revisions of previous estimates 4,093 (6,904) (2,811)
Extensions, discoveries and improved recovery 8,062 4,548 12,610
Production (49) (1,444) (1,493)
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves at end of the year 15,821 32,614 48,435
========= ========= =========

PROVED DEVELOPED RESERVES AT:
September 30, 2002 -- 11,840 11,840
September 30, 2001 2,483 15,658 18,141
September 30, 2000 2,325 14,913 17,238

S-34

PROVED RESERVES-NATURAL GAS (MMcf)
YEAR ENDED SEPTEMBER 30, 2002
Proved reserves beginning of the year 208,010 -- 208,010
Revisions of previous estimates -- -- --
Extensions, discoveries and improved recovery -- -- --
Production -- -- --
Sales of reserves in place (208,010) -- (208,010)
--------- --------- ---------
Proved reserves end of the year -- -- --
========= ========= =========

YEAR ENDED SEPTEMBER 30, 2001
Proved reserves beginning of the year 152,496 -- 152,496
Revisions of previous estimates 55,514 -- 55,514
Extensions, discoveries and improved recovery -- -- --
Production -- -- --
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves end of the year 208,010 -- 208,010
========= ========= =========

YEAR ENDED SEPTEMBER 30, 2000
Proved reserves beginning of the year -- -- --
Revisions of previous estimates -- -- --
Extensions, discoveries and improved recovery 152,496 -- 152,496
Production -- -- --
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves end of the year 152,496 -- 152,496
========= ========= =========

PROVED DEVELOPED RESERVES AT:
September 30, 2002 -- -- --
September 30, 2001 21,292 -- 21,292
September 30, 2000 17,801 -- 17,801

S-35

TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED
TO PROVED OIL AND NATURAL 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 we caution 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.

TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------
(amounts in thousands)

SEPTEMBER 30, 2002
Future cash inflow $ -- $ 469,837 $ 469,837
Future production costs -- 203,754) (203,754)
Future development costs -- (40,707) (40,707)
--------- --------- -----------
Future net revenue before income taxes -- 225,376 225,376
10% annual discount for estimated timing of cash flows -- (108,147 (108,147)
--------- --------- -----------
Discounted future net cash flows before income taxes -- 117,229 117,229
Future income taxes, discounted at 10% per annum -- (24,290) (24,290)
--------- --------- -----------
Standardized measure of discounted future net
cash flows $ -- $ 92,939 $ 92,939
========= ========= ===========

SEPTEMBER 30, 2001
Future cash inflow $ 630,340 $ 434,348 $ 1,064,688
Future production costs (373,458) (251,335) (624,793)
Future development costs (49,139) (37,020) (86,159)
--------- --------- -----------
Future net revenue before income taxes 207,743 145,993 353,736
10% annual discount for estimated timing of cash flows (99,343) (64,868) (164,211)
--------- --------- -----------
Discounted future net cash flows before income taxes 108,400 81,125 189,525
Future income taxes, discounted at 10% per annum (26,195) (10,477) (36,672)
--------- --------- -----------
Standardized measure of discounted future net
cash flows $ 82,205 $ 70,648 $ 152,853
========= ========= ===========

SEPTEMBER 30, 2000
Future cash inflow $ 584,346 $ 688,981 $ 1,273,327
Future production costs (395,238) (416,440) (811,678)
Future development costs (36,585) (34,035) (70,620)
--------- --------- -----------
Future net revenue before income taxes 152,523 238,506 391,029
10% annual discount for estimated timing of cash flows (78,006) (98,346) (176,352)
--------- --------- -----------
Discounted future net cash flows before income taxes 74,517 140,160 214,677
Future income taxes, discounted at 10% per annum (17,637) (25,435) (43,072)
--------- --------- -----------
Standardized measure of discounted future net
cash flows $ 56,880 $ 114,725 $ 171,605
========= ========= ===========

TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES

EQUITY AFFILIATES
-----------------------------------
2002 2001 2000
--------- --------- ---------
(AMOUNTS IN THOUSANDS)

Present Value at October 1 $ 152,853 $ 171,605 $ 175,913
Sales of oil and natural gas, net of related costs (23,644) (19,001) (20,977)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs 76,545 (39,880) (72,740)
Quantities (10,007) 8,881 (19,685)
Sales of reserves in place (82,205) -- --
Extensions, discoveries and improved recovery, net of future costs 2,031 18,767 73,542
Accretion of discount 7,065 21,468 22,359
Net change in income taxes 1,145 6,400 4,604
Development costs incurred 8,999 17,110 8,475
Changes in timing and other (39,843) (32,497) 114
--------- --------- ---------
Present Value at September 30 $ 92,939 $ 152,853 $ 171,605
========= ========= =========

S-36

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 Houston,
State of Texas, on the 28th day of March, 2003.

HARVEST NATURAL RESOURCES, INC.
(Registrant)

Date: March 28, 2003 By: /s/Peter J. Hill
--------------------------------
Peter J. Hill
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 28th day of March,
2003, on behalf of the Registrant in the capacities indicated:

Signature Title
- --------- -----

/s/ Peter J. Hill Director, President and Chief Executive
- --------------------------------------------------- Officer
Peter J. Hill

/s/ Steven W. Tholen Senior Vice President, Chief Financial
- --------------------------------------------------- Officer and Treasurer
Steven W. Tholen (Principal Financial Officer)

/s/ Kurt A. Nelson Vice President-Controller
- --------------------------------------------------- (Principal Accounting Officer)
Kurt A. Nelson

/s/ Stephen D. Chesebro' Chairman of the Board and Director
- ---------------------------------------------------
Stephen D. Chesebro'

/s/ John U. Clarke Director
- ---------------------------------------------------
John U. Clarke

/s/ H.H. Hardee Director
- --------------------------------------------------
H.H. Hardee

/s/ Patrick M. Murray Director
- ---------------------------------------------------
Patrick M. Murray

S-37

I, Peter J. Hill, certify that:

1. I have reviewed this annual report on Form 10-K of Harvest Natural
Resources, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;

b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and

c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):

a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Date: March 28, 2003
/s/ Peter J. Hill
-------------------------------------
Peter J. Hill
President and Chief Executive Officer

S-38

I, Steven W. Tholen, certify that:

1. I have reviewed this annual report on Form 10-K of Harvest Natural
Resources, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;

b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and

c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):

a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Date: March 28, 2003
/s/ Steven W. Tholen
-------------------------------------
Steven W. Tholen
Senior Vice President and
Chief Financial Officer

S-39

SCHEDULE II

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(in thousands)

ADDITIONS
-------------------------------
BALANCE AT CHARGED TO DEDUCTIONS BALANCE AT
BEGINNING OF CHARGED TO OTHER FROM END OF
YEAR INCOME ACCOUNTS RESERVES YEAR
------------- ------------- ------------- ------------- --------------

AT DECEMBER 31, 2002
Amounts deducted from applicable assets
Accounts receivable $ 6,512 $ 289 $ - $ 3,276 $ 3,525
Deferred tax valuation allowance 19,700 20,577 1,131 39,146
Investment at cost 1,350 - - - 1,350

AT DECEMBER 31, 2001
Amounts deducted from applicable assets
Accounts receivable $ 6,518 $ 330 $ - $ 336 $ 6,512
Deferred tax valuation allowance 54,207 14,352 (11,008) 37,851 19,700
Investment at cost 1,350 - - - 1,350

AT DECEMBER 31, 2000
Amounts deducted from applicable assets
Accounts receivable $ 6,187 $ 331 - - $ 6,518
Deferred tax valuation allowance 51,913 2,446 - 152 54,207
Investment at cost 1,350 - - - 1,350

S-40

SCHEDULE III
HARVEST NATURAL RESOURCES, INC.

LLC GEOILBENT
FINANCIAL STATEMENTS
30 SEPTEMBER 2002

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and
Owners of Limited Liability Company Geoilbent

In our opinion, the accompanying balance sheets and the related statements of
income, cash flows and changes in stockholders' equity, present fairly, in all
material respects, the financial position of LLC Geoilbent (the "Company") at 30
September 2002 and 2001, and the results of its operations and its cash flows
for each of the three years in the period ended 30 September 2002, in conformity
with accounting principles generally accepted in the United States of America.
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 of America, 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 our opinion.

The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Notes 4 and 11 to the
financial statements, the Company has a long-term debt facility for which it
will be unable to meet certain loan covenants and therefore the lender may
declare the loan to be in default and can accelerate the maturity. Accordingly,
this long-term debt has been classified in the accompanying financial statements
as a current liability resulting in a working capital deficit of approximately
US$ 35,266,000 as at 30 September 2002 which raises substantial doubt about the
Company's ability to continue as a going concern. Management's plans in regards
to this matter are also described in Note 4. The financial statements do not
include any adjustments that might result from the outcome of this uncertainty.

ZAO PricewaterhouseCoopers

Moscow, Russian Federation
28 February 2003

1

LLC GEOILBENT
BALANCE SHEETS
(expressed in thousand of US Dollars)

The accompanying notes are an integral part of these financial statements

2

LLC GEOILBENT
STATEMENTS OF INCOME
(expressed in thousand of US Dollars)

The accompanying notes are an integral part of these financial statements

3

LLC GEOILBENT
STATEMENTS OF CASHFLOWS
(expressed in thousand of US Dollars)

The accompanying notes are an integral part of these financial statements

4

LLC GEOILBENT
STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(expressed in thousands of US Dollars except as indicated)

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

Total stockholders'
Contributed capital Retained earnings equity
- ----------------------------------------------------------------------------------------------------------------

BALANCE AT 30 SEPTEMBER 1999 82,518 18,321 100,839
================================================================================================================

Net income and total comprehensive income - 18,905 18,905
- ----------------------------------------------------------------------------------------------------------------

BALANCE AT 30 SEPTEMBER 2000 82,518 37,226 119,744
================================================================================================================

Net income and total comprehensive income - 20,420 20,420
- ----------------------------------------------------------------------------------------------------------------

BALANCE AT 30 SEPTEMBER 2001 82,518 57,646 140,164
================================================================================================================

Net income and total comprehensive income - 3,885 3,885
- ----------------------------------------------------------------------------------------------------------------

BALANCE AT 30 SEPTEMBER 2002 82,518 61,531 144,049
================================================================================================================

The accompanying notes are an integral part of these financial statements

5

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

NOTE 1: ORGANIZATION

LLC Geoilbent (the "Company") is engaged in the development and production of
oil and gas in the North Gubkinskoye and South Tarasovskoye fields. These fields
are located in the West Siberian region of the Russian Federation, approximately
2,000 miles northeast of Moscow. The Company was established in December 1991 by
two Russian oil companies, OAO Purneftegas ("PNG") and OAO Purneftegasgeologia
("PNGG"), and Harvest Natural Resources, Inc. ("Harvest", formerly, Benton Oil
and Gas Company) of the United States, which contributed 33%, 33% and 34%,
respectively, of the Company's charter capital, in accordance with the Company's
Foundation Document. In January 2002, PNG and PNGG transferred their stakes in
the Company to OAO Minley, an affiliated company.

NOTE 2: BASIS OF PRESENTATION

The Company maintains its accounting records and prepares its statutory
financial statements in accordance with the Regulations on Accounting and
Reporting of the Russian Federation ("RAR"). The accompanying financial
statements have been prepared from these accounting records and adjusted as
necessary to comply with accounting principles generally accepted in the United
States of America ("US GAAP"). The Company has a year ending of 30 September for
US GAAP reporting purposes.

In preparing the financial statements in conformity with US GAAP, management
makes estimates and assumptions that affect the reported amounts of assets and
liabilities, revenues and expenses and the disclosure of contingent assets and
liabilities. Actual results could differ from such estimates.

Certain previously presented amounts have been reclassified to conform to the
presentation adopted during the current period. These reclassifications had no
impact on previously reported retained earnings.

REPORTING AND FUNCTIONAL CURRENCY. The Russian Rouble is the functional currency
(primary currency in which business is conducted) for the Company's operations
in the Russian Federation. The Company considers the US dollar as its reporting
currency as a significant portion of its business is conducted in US dollars and
management uses the US dollar to manage business risks and exposures, and to
measure performance of its business.

The measurement currency of the Company is either the Russian Rouble or the US
dollar depending on the nature of the activities. The transactions and balances
of the accompanying financial statements not already measured in US dollars have
been remeasured into US dollars in accordance with the relevant provisions of
SFAS No. 52 Foreign Currency Translation as applied to hyperinflationary
economies. Consequently, monetary assets and liabilities are translated at
closing exchange rates and non-monetary items are translated at historic
exchange rates and adjusted for any impairments. The statements of income and
cash flows have been translated using average exchange rates for the reporting
period. Translation differences resulting from the use of these exchange rates
have been included in the determination of net income and are included in
exchange gains/losses in the accompanying statements of income. The exchange
rates at 30 September 2002, and 30 September 2001, were 31.64 and 29.39,
respectively, Russian Roubles per US dollar.

6

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

Inflation, exchange restriction and controls. Exchange restrictions and controls
exist relating to converting Russian Roubles to other currencies. At present,
the Russian Rouble is not a convertible currency outside the Russian Federation.
Future movements in the exchange rates between the Russian Rouble and the US
dollar will affect the carrying value of the Company's Russian Rouble
denominated assets and liabilities. Such movements may also affect the Company's
ability to realize non-monetary assets represented in US dollars in the
accompanying financial statements. Accordingly, any translation of Russian
Rouble amounts to US dollars should not be construed as a representation that
such Russian Rouble amounts have been, could be, or will in the future be
converted into US dollars at the exchange rate shown or at any other exchange
rate.

NOTE 3: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

CASH AND CASH EQUIVALENTS. Cash and cash equivalents include all highly liquid
securities with original maturities of three months or less when acquired.

ACCOUNTS RECEIVABLE. Accounts receivable are presented at net realizable value
and include value-added and excise taxes which are payable to tax authorities
upon collection of such receivables.

INVENTORIES. Crude oil and petroleum products inventories are valued at the
lower of cost, using the first-in-first out method, or net realizable value.
Materials and supplies inventories are recorded at the lower of average cost or
net realizable value.

PROPERTY, PLANT AND EQUIPMENT. The Company follows the full cost method of
accounting for oil and gas properties. Under this method, all oil and gas
property acquisition, exploration, and development costs including internal
costs directly attributable to such activities are capitalized as incurred in
the Company's one cost center (full cost pool), which is the Russian Federation.
Payroll and other internal costs capitalized include salaries and related fringe
benefits paid to employees directly engaged in the acquisition, exploration and
development of oil and gas properties as well as all other directly identifiable
internal costs associated with these activities. Payroll and other internal
costs associated with production operations and general corporate activities are
expensed in the period incurred.

The full cost pool, including future development costs (including estimated
dismantlement, restoration and abandonment costs), net of prior accumulated
depletion, is depleted using the unit-of-production method based upon actual
production and estimates of proved oil and gas reserve quantities. Proceeds from
sales of oil and gas properties are credited to the full cost pool with no gain
or loss recognized unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves of oil and gas.

Pursuant to full cost accounting rules, capitalized costs less related
accumulated depletion and deferred income taxes may not exceed the sum of (1)
the present value of future net revenue from estimated production of proved oil
and gas reserves discounted at 10 percent; plus (2) the cost of properties not
being amortized, if any; plus (3) the lower of cost or estimated fair value of
unproved properties included in the costs being amortized, if any; less (4)
income tax effects related to differences in the book and tax basis of oil and
gas properties.

7

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

PENSION AND POST-EMPLOYMENT BENEFITS. The Company's mandatory contributions to
the governmental pension scheme are expensed when incurred.

REVENUE RECOGNITION. Revenue from the sale of crude oil is recognized when it is
dispatched to customers and title has transferred.

INCOME TAXES. Deferred income tax assets and liabilities are recognized for
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases, in accordance with SFAS No. 109, Accounting for Income
Taxes. Deferred income tax assets and liabilities are measured using enacted tax
rates in the years in which these temporary differences are expected to reverse.
Valuation allowances are provided for deferred income tax assets when management
believes it is more likely than not that the assets will not be realized.

RECENT ACCOUNTING STANDARDS. In July 2001, the Financial Accounting Standards
Board (the "FASB") issued Statement of Financial Accounting Standards ("SFAS")
No. 142, Goodwill and Other Intangible Assets ("SFAS 142"). SFAS 142 requires
that goodwill and intangible assets with indefinite lives no longer be amortized
and requires that such goodwill and intangible assets be tested annually for
impairment. SFAS 142 is effective for fiscal years beginning after December 15,
2001. Management does not believe that the adoption of SFAS 142 will have a
material effect on the Company's financial position or results of operations.

In September 2001, the FASB issued SFAS No. 143, Accounting for Assets
Retirement Obligations ("SFAS 143"). SFAS No. 143 requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of
the related long-lived asset. Subsequently, the asset retirement costs should be
allocated to expense using a systematic and rational method. SFAS No. 143 is
effective for fiscal years beginning after 15 June 2002. The Company has not yet
assessed the impact of SFAS No. 143 and therefore, at this time cannot
reasonably estimate the effect of this statement on its financial condition and
results of operations.

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets ("SFAS 144"), which clarified certain
implementation issues arising from SFAS 121. SFAS 144 is effective for years
beginning after December 15, 2001. Management does not believe that the adoption
of SFAS 144 will have a material effect on the Company's financial position or
results of operations.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities ("SFAS 146"). SFAS 146 addresses the recognition,
measurement, and reporting of costs associated with exit and disposal
activities, including restructuring activities, and nullifies the guidance in
Emerging Issues Task Force Issue No. 94-3. SFAS 146 is effective for exit or
disposal activities initiated after December 31, 2002. Management does not
believe that the adoption of SFAS 146 will have a material effect on the
Company's financial position or results of operations.

In November 2002, the International Practices Task Force (IPTF) concluded that
Russia has ceased being a highly inflationary economy as of 1 January 2003. As a
result of the Task Force conclusion, companies reporting under US GAAP in Russia
will be required to apply

8

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

the guidance contained in EITF No. 92-4 and EITF No. 92-8 as of 1 January 2003.
Management has not yet estimated the effect that EITF No. 92-4 and EITF No. 92-8
will have on the Company.

NOTE 4: GOING CONCERN

During the year ended 30 September 2002 the Company took steps to reduce its
working capital deficit. This included the renegotiation of debt falling due for
repayment to the European Bank for Reconstruction and Development (the "EBRD")
(Note 11), the repayment of debt, and the receipt of subordinated long-term
loans from the Company's stockholders. However, as at 30 September 2002, and 30
September 2001, the current liabilities of the Company exceeded its current
assets by USD 35,266 thousand and USD 24,992 thousand, respectively. Included in
current liabilities as at 30 September 2002 are loans repayable to the EBRD of
USD 22,000 thousand. This debt has been classified as current because the
Company will not be able to implement a new management information system by 1
May 2003, as required by the loan facility, and therefore will be in violation
of the loan facility covenants. Under the terms of the loan facility the EBRD
may declare the loan to be in default and can accelerate the maturity. The loan
facility also requires the Company to maintain a minimum working capital ratio.
The amended loan agreement discussed in Note 11 waived the maintenance of this
ratio through 30 September 2002. The Company's plans to re-establish the
required level of working capital is dependent upon the EBRD advancing
additional funds to the Company under the amended loan facility by 31 March
2003. There can be no assurance that the EBRD will provide this funding by 31
March 2003.

Because of the Company's significant working capital deficit, a substantial
portion of its cash flow must be utilized to pay accounts and taxes payable.
Additionally, in order to maintain or increase proved oil and gas reserves, the
Company must make substantial capital expenditures in 2003 and subsequently. The
Company's cash flow from operations is dependent on the level of oil prices,
which are historically volatile and are significantly impacted by the proportion
of production that the Company can sell on the export market. Historically, the
Company has supplemented its cash flow from operations with additional
borrowings or equity capital and may continue to do so. Should oil prices
decline for a prolonged period and should the Company not have access to
additional capital, the Company would need to reduce its capital expenditures,
which could limit its ability to maintain or increase production and, in turn,
meet its debt service requirements. Asset sales and financing are restricted
under the terms of debt agreements.

Management plans to further address the Company's working capital deficit by
reducing certain capital expenditures and funding its 2003 debt service and
planned capital expenditures with cash flows from existing producing properties
and its development drilling program. Additionally, the Company is working with
the EBRD to resolve issues relating to the loan covenant violations. The
accompanying financial statements do not include any adjustments that might
result if the Company were unable to continue as a going concern.

NOTE 5: CASH AND CASH EQUIVALENTS

Included in cash and cash equivalents as at 30 September 2002, and 2001,
respectively, are Russian Rouble denominated amounts totaling RR 18.3 million
(USD 578 thousand) and RR 129.4 million (USD 4,402 thousand).

9

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

Restricted cash consists of deposits with lending institutions to pay interest
and principal as discussed in Note 11. As at 30 September 2002, the amount of
restricted cash was USD 1,469 thousand (2001: USD 10,208 thousand). These
accounts are maintained in offshore US Dollar denominated accounts.

NOTE 6: FINANCIAL INSTRUMENTS

FAIR VALUES. The estimated fair values of financial instruments are determined
with reference to various market information and other valuation methodologies
as considered appropriate, however considerable judgment is required in
interpreting market data to develop these estimates. Accordingly, the estimates
are not necessarily indicative of the amounts that the Company could realize in
a current market transaction. The methods and assumptions used to estimate fair
value of each class of financial instrument are presented below.

CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE. The
carrying amount of these items are a reasonable approximation of their fair
value.

SHORT-TERM AND LONG-TERM DEBT. Loan arrangements have both fixed and variable
interest rates that reflect the currently available terms and conditions for
similar debt. The carrying value of this debt is a reasonable approximation of
its fair value.

CREDIT RISKS. A significant portion of the Company's accounts receivable are
from domestic and foreign customers, and advances are made to domestic
suppliers. Although collection of these amounts could be influenced by economic
factors affecting these entities, management believes there is no significant
risk of loss to the Company beyond the provisions already recorded, provided
that economic difficulties in the Russian Federation do not deteriorate (Note
17).

NOTE 7: ACCOUNTS RECEIVABLE AND ADVANCES TO SUPPLIERS

Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------

Trade accounts receivable 1,387 2,158
Recoverable value-added tax 3,515 3,640
Advances to suppliers 1,193 723
Advances to customs 137 597
Other receivables 76 147
- ---------------------------------------------------------------------------------------------------------------
TOTAL ACCOUNTS RECEIVABLE AND ADVANCES TO SUPPLIERS 6,308 7,265
===============================================================================================================

10

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

NOTE 8: INVENTORIES

Thousands of US Dollars 30 September 2002 30 September 2001
--------------------------------------------------------------------------------------------------------------

Materials and supplies 6,905 12,814
Crude oil 296 751
--------------------------------------------------------------------------------------------------------------
TOTAL INVENTORIES 7,201 13,565
===============================================================================================================

NOTE 9: OIL AND GAS PRODUCING PROPERTIES

Thousands of US dollars 30 September 2002 30 September 2001
--------------------------------------------------------------------------------------------------------------

Oil and gas producing properties, cost 278,459 251,990
Accumulated depletion (92,470) (65,302)
--------------------------------------------------------------------------------------------------------------
OIL AND GAS PRODUCING PROPERTIES, NET BOOK VALUE 185,989 186,688
===============================================================================================================

The Company's oil and gas fields are situated on land belonging to the
Government of the Russian Federation. The Company obtained licenses from the
local authorities and pays unified production taxes to explore and produce oil
and gas from these fields. Licenses will expire in September 2018 for the North
Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However,
under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the
licenses may be extended over the economic life of the lease at the Company's
option. Management intends to extend such licenses for properties that are
expected to produce subsequent to their expiry dates. Estimates of proved
reserves extending past 2018 represent approximately 5 percent of total proved
reserves.

Temporarily excluded from the full cost oil and gas properties depletion pool as
at 30 September 2002 are costs incurred to date of USD 800 thousand relating to
unevaluated projects for a gas processing plant and geological and geophysical
work for the Urabor-Yahinskoe exploration license, for both of which the
ultimate feasibility and estimates of proven reserves have not yet been
established. Management expects that decisions regarding completion of both
projects will be taken during the next year.

NOTE 10: SHORT-TERM BORROWINGS

Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------

International Moscow Bank ("IMB") - 3,000
- ---------------------------------------------------------------------------------------------------------------

TOTAL SHORT-TERM BORROWINGS - 3,000
===============================================================================================================

NOTE 11: LONG-TERM DEBT

Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------

EBRD 22,000 33,000
IMB 550 7,750
Subordinated loans - related parties 7,500 -
Less: current portion ( 22,550) (18,200)
- ---------------------------------------------------------------------------------------------------------------

TOTAL LONG-TERM DEBT 7,500 22,550
===============================================================================================================

11

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

EBRD LOAN. At 30 September 2002, the outstanding balance of loans with the EBRD
totaled USD 22 million. On 23 September 2002, the Company signed an amended loan
agreement with the EBRD for the maximum borrowing of USD 50 million. This
amended loan facility became effective subsequent to 30 September 2002. Under
the loan agreement, the use of loan proceeds is restricted to the repayment of
accounts payable and development of oil and gas reserves. The new loan facility
is to be repaid in 6 equal semi-annual installments commencing January 2004. The
interest rate under the new loan agreement is linked to the London interbank
offer rate ("LIBOR") and an agreed upon margin. The Company must hold as
restricted cash 30 percent of the total of principal and interest to be paid at
the next repayment date.

LIBOR interest rates ranged from 1.84 percent to 3.5 percent in 2002 (2001: 3.5
percent to 6.94 percent, 2000: 6.6063 to 7.064 percent). The annual weighted
average interest rates on these loans varied between 8.59 percent and 11.71
percent for the year ended 30 September 2002 (2001: 14.93 percent and 15.17
percent, 2000: 10.88 percent and 15.14 percent). The outstanding loan amount to
the EBRD is collaterized by most significant immovable assets and crude oil
export sales of the Company.

The EBRD loan agreement includes certain covenants which include, among other
things, the maintenance of financial ratios. If the Company fails to meet these
requirements for two concecutive quarters it will result in an event of default
whereby the EBRD may, at its option, demand payment of the outstanding principal
and interest. Although the Company was not in compliance with maintaining its
current ratio requirement of 1.1 as at 30 September 2002, as part of the amended
loan facility discussed above, the EBRD has waived the covenant requirement
through the quarters ended September 2002. As dicussed in Note 4, the Company
will be in violation of the loan facility covenants which would allow the EBRD
to declare a default and accelerate the maturity of this loan. The Company has
accordingly classified the USD 22,000 in debt as a current liability.

SUBORDINATED LOANS - RELATED PARTIES. During 2002, stockholders OAO Minley and
Harvest Natural Resources provided the Company with subordinated loans totaling
USD 7.5 million. The loans are unsecured and repayable commencing January 2004.
Interest rates are set at 2% for the Minley loan, and LIBOR for the Harvest
loan.

IMB LOAN. On 14 May 2001, the Company obtained a USD 3.3 million loan from IMB
repayable by six payments of USD 0.55 million commencing 1 August 2001, ending 1
November 2002, bearing interest of LIBOR plus 6.5 percent. The loan is
collaterized by moveable property of the South-Tarasovskoye field.

Aggregate maturities of long-term debt outstanding at 30 September 2002 are as
follows:

Thousands of US dollars
- ---------------------------------------------------------------------------------------------------------------

Year ended 30 September 2004 7,500
- ---------------------------------------------------------------------------------------------------------------

TOTAL LONG-TERM DEBT 7,500
===============================================================================================================

12

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

NOTE 12: TAXES PAYABLE

Taxes payable were as follows:

Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------

Value Added Tax 1,445 3,305
Income tax 1,176 1,826
Royalty 896 923
Mineral restoration tax 152 767
Road users tax 642 176
Unified production tax 6,703 -
Property taxes 1,121 438
Other taxes 219 49
- ---------------------------------------------------------------------------------------------------------------
TOTAL TAXES PAYABLE 12,354 7,484
===============================================================================================================

NOTE 13: CONTRIBUTED CAPITAL

Capital contributions are as follows:

Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------

Purneftegasgeologia - 27,645
Purneftegas - 27,088
Harvest Natural Resources 27,785 27,785
OAO Minley 54,733 -
- ---------------------------------------------------------------------------------------------------------------
TOTAL CONTRIBUTED CAPITAL 82,518 82,518
===============================================================================================================

All capital contributions have been made since inception in accordance with the
Company's Foundation Document.

Reserves available for distribution to shareholders are based on the statutory
accounting reports of the Company, which are prepared in accordance with
Regulations on Accounting and Reporting of the Russian Federation and which
differ from U.S. GAAP. Russian legislation identifies the basis of distribution
as net income. For 2001, the current year statutory net income for the Company
as reported in the annual statutory accounting reports was RR 551 million.
However, current legislation and other statutory laws and regulations dealing
with distribution rights are open to legal interpretation and, consequently,
actual distributable reserves may differ from the amount disclosed.

NOTE 14: REVENUES

Revenues for the years ended 30 September 2002, 2001 and 2000, consisted of the
following:

Thousand of US dollars 30 September 2002 30 September 2001 30 September 2000
- ---------------------------------------------------------------------------------------------------------------

Crude oil - export (Europe and CIS) 47,751 83,889 50,807
Crude oil - domestic 40,778 10,900 13,195
Refined products - domestic 2,764 6,231 14,733
Other operating revenues 305 139 70
- ---------------------------------------------------------------------------------------------------------------
TOTAL SALES AND OTHER OPERATING REVENUES 91,598 101,159 78,805
===============================================================================================================

13

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

NOTE 15: TAXES

Presented below is a reconciliation between the provision for income taxes and
taxes determined by applying the statutory tax rate as applied in the Russian
Federation to income before income taxes.

Thousand of US dollars 30 September 2002 30 September 2001 30 September 2000
- -----------------------------------------------------------------------------------------------------------------

Income before income taxes 4,187 27,171 25,226
- -----------------------------------------------------------------------------------------------------------------
Theoretical income tax expense at statutory rate 1,005 9,509 7,568
(24% in 2002; 35% in 2001; 30% in 2000)
Increase (reduction) due to:
Change in valuation allowance 80 1,810 348
Non-deductible expenses 2,894 2,693 2,600
Investment tax credits (5,348) (6,821) (5,142)
Change in statutory tax rate 595 (750) -
Tax penalties and interest 1,135 517 27
Foreign exchange effects and other (59) (207) 920
- -----------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE 302 6,751 6,321
=================================================================================================================

Deferred income taxes reflect the impact of temporary differences between the
amount of assets and liabilities recognized for financial reporting purposes and
such amounts recognized for statutory tax purposes. Net deferred tax assets are
comprised of the following, at 30 September 2002 and 2001:

Thousand of US dollars 30 September 2002 30 September 2001
- -----------------------------------------------------------------------------------------------------------------

Inventories 93 137
Accounts receivable 258 -
Accounts payable and accrued liabilities 430 -
Losses carried forward 2,502 2,403
Property, plant and equipment 4,810 2,971
- -----------------------------------------------------------------------------------------------------------------
Total deferred tax assets 8,093 5,511
Less: Valuation allowance (5,591) (5,511)
- -----------------------------------------------------------------------------------------------------------------
NET DEFERRED TAX ASSET 2,502 -
=================================================================================================================

Losses carried forward represent those losses for tax purposes which, according
to legislation, the Company is permitted to offset against future taxable
earnings in the periods up to 2008, and is subject to limitations of no more
than 30% of the Company's tax liabilities for the tax reporting period.

As at 30 September 2002, management of the Company have assessed the
recoverability of the Company's deferred tax assets and believes that with
changes in the tax law it will now be able to realize the tax losses carried
forward. Accordingly, the Company has provided a valuation allowance as at 30
September 2002, and 2001, of USD 5,591 thousand and USD 5,304 thousand,
respectively, against the amount of deferred tax assets.

Deferred income taxes are classified as follows:

Thousands of US dollars 30 September 2002 30 September 2001
----------------------------------------------------------------------------------------------------------------

Deferred income tax, current 1,806 -
Deferred income tax, non-current 696 -
----------------------------------------------------------------------------------------------------------------
TOTAL NET DEFERRED TAX ASSET 2,502 -
=================================================================================================================

14

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

TAXES OTHER THAN INCOME TAX. The Company is subject to a number of taxes other
than on income which are detailed below.

Thousands of US dollars 30 September 2002 30 September 2001 30 September 2000
- ---------------------------------------------------------------------------------------------------------------

Export duties 5,376 10,922 4,322
Excise tax 535 1,548 813
Royalty 2,254 4,867 4,028
Mineral restoration tax 885 4,596 4,510
Road users tax 860 1,427 2,201
Unified production tax 14,221 - -
Property taxes 1,994 1,424 780
Other taxes 1,532 1,227 1,632
- ---------------------------------------------------------------------------------------------------------------
TOTAL TAXES OTHER THAN INCOME TAX 27,657 26,011 18,286
===============================================================================================================

Beginning 1 January 2002, mineral restoration tax, royalty tax and excise tax on
crude oil production were abolished and replaced by the unified natural
resources production tax. Through 31 December 2004, the base rate for the
unified natural resources production tax is set at RR 340 per metric ton of
crude oil produced, and is to be adjusted depending on the market price of Urals
blend and the RR/USD exchange rate. The tax becomes nil if the Urals blend price
falls to or below USD 8.00 per barrel. From 1 January 2005, the unified natural
resources production tax rate is set by law at 16.5 percent of crude oil
revenues recognized by the Company based on Regulations on Accounting and
Reporting of the Russian Federation.

NOTE 16: RELATED PARTY TRANSACTIONS

As of 30 September 2002 and 2001, the Company had the following balances with
its stockholders. These balances are included in the balance sheet within
accounts receivable, accounts payable and long-term debt as appropriate.

Thousand of US Dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------

Accounts receivable
Purneftegasgeologia and affiliated entities 63 -

Accounts payable
Purneftegasgeologia and affiliated entities 574 2,113
Purneftegas and affiliated entities 22 182
Harvest Natural Resources 3,354 -

Long-term debt
Harvest Natural Resources 2,500 -
Minley 5,000 -
- ---------------------------------------------------------------------------------------------------------------
TOTAL 11,513 2,295
===============================================================================================================

HARVEST NATURAL RESOURCES. Accounts payable as of 30 September 2002 resulted
from Harvest providing insurance on behalf of the Company and personnel
services. During 2001 and 2000 the Company paid to Harvest USD 717 thousand and
USD 2,000, respectively, for prepaid loan costs relating to the creation of the
EBRD/IMB loans.

PURNEFTEGAS. During 2002, 2001 and 2000, Purneftegas and affiliated entities
provided well maintenance services and supplies to the Company for a total value
of approximately USD

15

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

312 thousand, USD 248 thousand, and USD 188 thousand, respectively. The Company
sold materials to PNG and affiliated entities during 2002 for a total value of
approximately USD 260 thousand.

PURNEFTEGASGEOLOGIA. During 2002, 2001 and 2000, Purneftegasgeologia and
affiliated entities provided services to the Company for a total value of
approximately USD 2,414 thousand, USD 4,193 thousand, and USD 2,156 thousand,
respectively. Services consisted of drilling, well maintenance and other related
work. The Company sold crude oil to PNGG and affiliated entities for a total
value of USD 24 thousand, USD 56 thousand, and USD 80 thousand during 2002,
2001, and 2000, respectively, and materials during 2002 for a total value of
approximately USD 613 thousand.

MINLEY. During 2002, the Company paid USD 4.9 million to Minley in settlement at
face value of promissory notes originally issued to the Company's suppliers and
contractors.

NOTE 17: COMMITMENTS AND CONTINGENT LIABILITIES

ECONOMIC AND OPERATING ENVIRONMENT IN THE RUSSIAN FEDERATION. Whilst there have
been improvements in the economic situation in the Russian Federation in recent
years, the country continues to display some characteristics of an emerging
market. These characteristics include, but are not limited to, the existence of
a currency that is not freely convertible in most countries outside of the
Russian Federation, restrictive currency controls, and relatively high
inflation.

The prospects for future economic stability in the Russian Federation are
largely dependent upon the effectiveness of economic measures undertaken by the
government, together with legal, regulatory, and political developments.

TAXATION. Russian tax legislation is subject to varying interpretations and
changes occurring frequently, which may be retroactive. Further, the
interpretation of tax legislation by tax authorities as applied to the
transactions and activity of the Company may not coincide with that of
management. As a result, the tax authorities may challenge transactions and the
Company may be assessed additional taxes, penalties and interest, which may be
significant. The tax periods remain open to review by the tax and customs
authorities for three years. The Company cannot predict the ultimate amount of
additional assessments, if any, and the timing of their related settlements with
certainty, but expects that additional liabilities, if any, arising will not
have a significant effect on the accompanying financial statements.

ENVIRONMENTAL MATTERS. Environmental regulations and their enforcement are
continually being considered by governmental authorities, and the Company
periodically evaluates its obligations related thereto. As obligations are
determined, they are provided over the estimated remaining lives of the related
oil and gas reserves, or recognized immediately, depending on their nature. The
outcome of environmental liabilities under proposed or any future legislation,
or as a result of stricter enforcement of existing legislation, cannot
reasonably be estimated. Under existing legislation, management believes there
are no probable liabilities, which would have a materially adverse effect on the
financial position or the results of the Company.

16

LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

LEGAL CONTINGENCIES. The Company is currently seeking to recover from tax
authorities royalty taxes paid during the period from 1996 to 2001 in the amount
of approximately RR 217 million ($6.9 million) based on the Company's
interpretation of applicable laws and regulations during this period. The case
is currently being heard in the courts and the final outcome is uncertain at
this time. No asset has been recognized related to this claim.

The Company is the named defendant in a number of lawsuits as well as the named
party in numerous other proceedings arising in the ordinary course of business.
While the outcomes of such contingencies, lawsuits or other proceedings cannot
be determined at present, management believes that any resulting liabilities
will not have a materially adverse effect on the operating results or the
financial position of the Company

INSURANCE. At 30 September 2002 and 2001, the Company held limited insurance
policies in relation to its assets and operations, or in respect of public
liability or other insurable risks. Since the absence of insurance alone does
not indicate that an asset has been impaired or a liability incurred, no
provision has been made in the financial statements for unspecified losses.

17

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL 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 our oil and natural gas exploration and
production activities. 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 our 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.

TABLE I - TOTAL COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION
AND DEVELOPMENT ACTIVITIES:

Year ended Year ended Year ended
Thousand of US Dollars 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------

Development costs 25,004 33,583 39,087
Exploration costs 1,465 6,100 823
- ----------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED IN OIL AND NATURAL GAS 26,469 39,683 39,910
ACQUISITION, EXPLORATION, AND DEVELOPMENT
ACTIVITIES
================================================================================================================

TABLE II - CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING
ACTIVITIES:

As at As at
Thousand of US Dollars 30 September 2002 30 September 2001
- ----------------------------------------------------------------------------------------------------------------

Proved property costs 277,659 251,990
Costs excluded from amortization 800 -
Oilfield inventories 6,905 12,814
Less accumulated depletion and impairment (92,470) (65,302)
- ----------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING
ACTIVITIES 192,894 199,502
================================================================================================================

TABLE III - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES:

In accordance with SFAS 69, results of operations for oil and natural gas
producing activities neither include general corporate overhead and monetary
effects, nor their associated tax effects. Income tax is based on statutory
rates for the year, adjusted for tax deductions, tax credits and allowances.

18

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

Year ended Year ended Year ended
Thousand of US Dollars 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------

Oil and natural gas sales 91,291 100,768 78,577
Expenses:
Operating, selling and distribution expenses
and taxes other than on income 49,713 47,302 31,856
Depletion 27,168 14,918 9,557
Income tax expense 5,750 11,006 9,723
--------------------------------------------------------------
Total expenses 82,361 73,226 51,136
- ----------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS
PRODUCING ACTIVITIES 8,660 27,542 27,441
================================================================================================================

TABLE IV - QUANTITIES OF OIL AND NATURAL 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.

The Company's oil and gas fields are situated on land belonging to the
Government of the Russian Federation. The Company obtained licenses from the
local authorities and pays unified production taxes to explore and produce oil
and gas from these fields. Licenses will expire in September 2018 for the North
Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However,
under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the
licenses may be extended over the economic life of the lease at the Company's
option. Management intends to extend such licenses for properties that are
expected to produce subsequent to their expiry dates. Estimates of proved
reserves extending past 2018 represent approximately 5 percent of total proved
reserves.

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 we consider 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 or for which transportation and/or marketing contracts are not in
place.

Proved developed reserves are reserves which can be expected to be recovered
through existing wells with existing equipment and existing 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

19

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

non producing 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 natural 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.

Changes in previous estimates of proved reserves result from new information
obtained from production history and changes in economic factors.

The evaluations of the oil and natural gas reserves were prepared by Ryder-Scott
Company, independent petroleum engineers.

PROVED RESERVES-CRUDE OIL, CONDENSATE AND Year ended Year ended Year ended
NATURAL GAS LIQUIDS (MBbls) 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------

PROVED RESERVES BEGINNING OF YEAR 87,259 95,924 107,100
Revisions of previous estimates (10,163) (16,454) (20,306)
Extensions, discoveries and improved recovery 4,391 12,974 13,377
Production (6,912) (5,185) (4,247)
- ----------------------------------------------------------------------------------------------------------------
PROVED RESERVES, END OF YEAR 74,575 87,259 95,924
================================================================================================================
PROVED DEVELOPED RESERVES 34,824 46,052 43,861
================================================================================================================

TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO
PROVED OIL AND NATURAL 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 we caution 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

20

LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------

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.

Year ended Year ended Year ended
Thousand of US Dollars 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------

Future cash inflow 1,381,874 1,277,494 2,026,415
Future production costs (599,277) (739,221) (1,224,824)
Future development costs (119,725) (108,882) (100,103)
- ----------------------------------------------------------------------------------------------------------------
Future net revenue before income taxes 662,872 429,391 701,488
10% annual discount for estimated timing of cash
flows (318,079) (190,788) (289,253)
- ----------------------------------------------------------------------------------------------------------------
Discounted future net cash flows before income taxes 344,793 238,603 412,235

Future income taxes, discounted at 10% per annum (71,442) (30,815) (74,809)
- ----------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS 273,351 207,788 337,426
================================================================================================================

TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES

Year ended Year ended Year ended
Thousand of US Dollars 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------

PRESENT VALUE AT BEGINNING OF PERIOD 207,788 337,426 497,285
Sales of oil and natural gas, net of related costs (69,541) (54,015) (59,344)
Revisions to estimates of proved reserves:
Net changes in prices, development and
production costs 225,132 (107,356) (148,965)
Quantities (29,432) (71,709) 57,424
Extensions, discoveries and improved recovery,
net of future costs 5,974 55,197 (92,559)
Accretion of discount 23,862 41,224 63,338
Net change of income taxes 3,367 43,994 61,282
Development costs incurred 26,468 37,953 22,391
Changes in timing and other (120,267) (74,926) (63,426)
- ----------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT END OF PERIOD 273,351 207,788 337,426
================================================================================================================

21

EXHIBIT INDEX