HARVEST NATURAL RESOURCES INC - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

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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
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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
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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
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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
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(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
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Total expenses 59,159 72,433 82,863
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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
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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