HARVEST NATURAL RESOURCES INC - 10-Q Quarterly Report

Back to GetFilings.com

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

FORM 10-Q

(Mark One)
Quarterly Report Under Section 13 or 15(d)
[X] of the Securities Exchange Act of 1934
For the Quarterly Period Ended June 30, 2002 or

Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from _____ to _____

COMMISSION FILE NO. 1-10762

----------

HARVEST NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)

DELAWARE 77-0196707
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)

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

Registrant's telephone number, including area code (281) 579-6700

BENTON OIL AND GAS COMPANY
(former name, former address, and former fiscal year
if changed since last report)

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
--- ---

At August 5, 2002, 35,020,905 shares of the
Registrant's Common Stock were outstanding.

2

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES

3

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)

See accompanying notes to consolidated financial statements.

4

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data, unaudited)

See accompanying notes to consolidated financial statements.

5

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

See accompanying notes to consolidated financial statements.

6

SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES

During the six months ended June 30, 2002 and 2001, we recorded an allowance for
doubtful accounts related to amounts owed to us by our former Chief Executive
Officer including the portions of the note secured by our stock and stock
options (see Note 11).

See accompanying notes to consolidated financial statements.

7

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

THREE AND SIX MONTHS ENDED JUNE 30, 2002 (UNAUDITED)

NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

INTERIM REPORTING

In our opinion, the accompanying unaudited consolidated financial statements
contain all adjustments (consisting of only normal recurring accruals) necessary
to present fairly the financial position as of June 30, 2002, and the results of
operations for the three and six month periods ended June 30, 2002 and 2001 and
cash flows for the six month periods ended June 30, 2002 and 2001. The unaudited
financial statements are presented in accordance with the requirements of Form
10-Q and do not include all disclosures normally required by accounting
principles generally accepted in the United States of America. Reference should
be made to our consolidated financial statements and notes thereto included in
our Annual Report on Form 10-K for the year ended December 31, 2001, for
additional disclosures, including a summary of our accounting policies.

The results of operations for the three and six month periods ended June 30,
2002 are not necessarily indicative of the results to be expected for the full
year.

ORGANIZATION

We engage in the exploration, development, production and management of oil and
gas properties. We conduct our business principally in Venezuela and Russia.
Effective May 20, 2002, we changed our name to Harvest Natural Resources, Inc.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of all wholly owned
and majority owned subsidiaries. The equity method of accounting is used for
companies and other investments in which we have significant influence. All
intercompany profits, transactions and balances have been eliminated. We account
for our investment in Geoilbent, Ltd. ("Geoilbent") and Arctic Gas Company
("Arctic Gas") based on a fiscal year ending September 30 (see Note 2).

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statement and the reported amounts of revenue and expenses during
the reporting period. The most significant estimates pertain to proved oil,
plant products and gas reserve volumes and future development costs. Actual
results could differ from those estimates.

ACCOUNTS AND NOTES RECEIVABLE

Allowance for doubtful accounts related to employee notes was $6.7 million and
$6.5 million at June 30, 2002 and December 31, 2001, respectively (see Note 11).

MINORITY INTERESTS

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

MARKETABLE SECURITIES

Marketable securities are carried at amortized cost. The marketable securities
we may purchase are limited to those defined as Cash Equivalents in the
indentures for our senior unsecured note. Cash Equivalents may be comprised of
high-grade debt instruments, demand or time deposits, bankers' acceptances and
certificates of deposit or acceptances of large U.S. financial institutions and
commercial paper of highly rated U.S. corporations, all having maturities of no
more than 180 days. Our marketable securities at cost, which approximates fair
value, consisted of $12.9 million in commercial paper at June 30, 2002.

8

COMPREHENSIVE INCOME

Statement of Financial Accounting Standards No. 130 ("SFAS 130") requires that
all items that are required to be recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements. We did not
have any items of other comprehensive income during the three and six month
periods ended June 30, 2002 or June 30, 2001 and, in accordance with SFAS 130,
have not provided a separate statement of comprehensive income.

DERIVATIVES AND HEDGING

Statement of Financial Accounting Standards No. 133 ("SFAS 133"), as amended,
establishes accounting and reporting standards for derivative instruments and
hedging activities. We have not used derivative or hedging instruments since
1996.

EARNINGS PER SHARE

Basic earnings per common share ("EPS") is computed by dividing income available
to common stockholders by the weighted average number of common shares
outstanding for the period. The weighted average number of common shares
outstanding for computing basic EPS was 34.7 million and 34.4 million for the
three and six months ended June 30, 2002, respectively, and 33.9 million for
each of the three and six months ended June 30, 2001. Diluted EPS reflects the
potential dilution that could occur if securities or other contracts to issue
common stock were exercised or converted into common stock. The weighted average
number of common shares outstanding for computing diluted EPS, including
dilutive stock options, was 36.4 million and 35.7 million for the three and six
months ended June 30, 2002, respectively, and 33.9 million and 34.0 million for
the three and six months ended June 30, 2001, respectively.

PROPERTY AND EQUIPMENT

We follow the full cost method of accounting for oil and gas properties with
costs accumulated in cost centers on a country by country basis, subject to a
cost center ceiling (as defined by the Securities and Exchange Commission). All
costs associated with the acquisition, exploration, and development of oil and
natural gas reserves are capitalized as incurred, including exploration overhead
of $0.4 million for the six months ended June 30, 2001, and capitalized interest
of $0.5 million and $0.4 million for the six months ended June 30, 2002 and
2001, respectively. Only overhead that is directly identified with acquisition,
exploration or development activities is capitalized. All costs related to
production, general corporate overhead and similar activities are expensed as
incurred.

The costs of unproved properties are excluded from amortization until the
properties are evaluated. Excluded costs attributable to the China and other
cost centers were $3.5 million and $16.9 million at June 30, 2002 and December
31, 2001, respectively. We regularly evaluate our unproved properties on a
country by country basis for possible impairment. If we abandon all exploration
efforts in a country where no proved reserves are assigned, all exploration and
acquisition costs associated with the country are expensed. Due to the
unpredictable nature of exploration drilling activities, the amount and timing
of impairment expenses are difficult to predict with any certainty. Of the $3.5
million, $2.9 million relates to the acquisition of Benton Offshore China
Company and exploration expenditures related to its WAB-21 property (See Note
10). The remaining $0.6 million at June 30, 2002 relates to the Lakeside
Prospect.

All capitalized costs and estimated future development costs (including
estimated dismantlement, restoration and abandonment costs) of proved reserves
are depleted using the units of production method based on the total proved
reserves of the country cost center. Depletion expense, which was substantially
all attributable to the Venezuelan cost center for the six months ended June 30,
2002 and 2001, was $14.1 million and $10.6 million ($2.82 and $2.12 per
equivalent barrel), respectively. Depreciation of furniture and fixtures is
computed using the straight-line method with depreciation rates based upon the
estimated useful life of the property, generally five years. Leasehold
improvements are depreciated over the life of the applicable lease. Depreciation
expense was $0.6 million and $1.7 million for the three months ended June 30,
2002 and 2001, respectively. Depreciation expense was $0.7 million and $2.1
million for the six months ended June 30, 2002, respectively.

NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002. We are currently
assessing the impact of SFAS No. 143 and therefore, at this time, cannot
reasonably estimate the effect of this statement on its consolidated financial
position, results of operations or cash flows.

9

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

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

NOTE 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES

Investments in Geoilbent and Arctic Gas are accounted for using the equity
method due to the significant influence we exercise over their operations and
management. Investments include amounts paid to the investee companies for
shares of stock or joint venture interests and other costs incurred associated
with the acquisition and evaluation of technical data for the oil and natural
gas fields operated by the investee companies. Other investment costs are
amortized using the units of production method based on total proved reserves of
the investee companies. On February 27, 2002, we entered into a Sale and
Purchase Agreement to sell our entire 68 percent stock ownership interest in
Arctic Gas Company to a nominee of the Yukos Oil Company for $190 million plus
approximately $30 million as repayment of intercompany loans owed to us by
Arctic Gas ("Arctic Gas Sale"). On March 28, 2002, we received the first payment
($121.0 million) of proceeds. On April 12, 2002, we received the balance of the
sales proceeds plus repayment of the intercompany loan, and transferred the
Arctic Gas shares. Equity in earnings of Geoilbent and Arctic Gas are based on a
fiscal year ending September 30. Arctic Gas equity earnings for the twelve days
of April will be reflected in the three months ending September 30, 2002. No
dividends have been paid to us from Geoilbent or Arctic Gas.

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

10

NOTE 3 - LONG-TERM DEBT AND LIQUIDITY

LONG-TERM DEBT

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

In May 1996, we issued $125 million in 11.625 percent senior unsecured notes due
May 1, 2003 ("2003 Notes"), of which we had previously repurchased $17 million
in prior periods and the remaining $108 million at March 29, 2002. In November
1997, we issued $115 million in 9.375 percent senior unsecured notes due
November 1, 2007 ("2007 Notes"), of which we earlier repurchased $10 million at
their par value. In April 2002, we repurchased $20 million of the 2007 Notes at
their discounted value for cash of $18.8 million plus accrued interest. A
pre-tax gain of $0.9 million was recognized on these notes. Interest on the 2007
Notes is due May 1 and November 1 of each year. The indenture agreement provides
for certain limitations on liens, additional indebtedness, certain investments
and capital expenditures, dividends, mergers and sales of assets. At June 30,
2002, we were in compliance with all covenants of the indenture.

In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan
commercial bank, in the form of two loans, for construction of a 31-mile oil
pipeline connecting the Tucupita Field production facility with the Uracoa
central processing unit. The first loan, with an original principal amount of $6
million, bears interest payable monthly based on 90-day London Interbank
Borrowing Rate ("LIBOR") plus 5 percent with principal payable quarterly for
five years. The second loan, in the amount of 4.4 billion Venezuelan Bolivars
("Bolivars") (approximately $6.3 million), bears interest payable monthly based
on a mutually agreed interest rate determined quarterly, or a six-bank average
published by the central bank of Venezuela. The interest rate for the quarter
ending June 30, 2002 was 58 percent with a negative effective interest rate
taking into account exchange gains resulting from the devaluation of the Bolivar
during the quarter. The loans provide for certain limitations on dividends,
mergers and sale of assets. At June 30, 2001, we were in compliance with all
covenants of the loans.

In 2001, a dispute arose over collection by municipal taxing regimes on the
Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit
resulting in overpayments and underpayments to adjacent municipalities. As
settlement, a portion of future municipal tax payments will be offset by the
municipal tax that was originally overpaid. The present value of the long-term
portion of the settlement liability is $0.7 million at December 31, 2001. The
entire balance was repaid or reclassified to short-term by June 30, 2002.

LIQUIDITY

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

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

o geological, geophysical and seismic costs; and

o acquisition of interests in oil and gas properties.

The amount of available capital will affect the scope of our operations and the
rate of our growth. As of June 30, 2002, our cash and marketable securities
balances were $69.6 million. Our future rate of growth also depends
substantially upon the prevailing prices of oil. Prices also affect the amount
of cash flow available for capital expenditures and our ability to service our
debt. Additionally, our ability to pay interest on our debt and general
corporate overhead is partially dependent upon the ability of

11

Benton-Vinccler and Geoilbent to make loan repayments, dividends and other cash
payments to us; however, there may be contractual obligations or legal
impediments to receiving dividends or distributions from our subsidiaries.

On April 12, 2002, we concluded the Arctic Gas Sale. The proceeds from the sale
were used to redeem all $108.0 million senior unsecured notes due in 2003 plus
$20.0 million senior unsecured notes due in 2007. Among the options under
consideration for use of the remaining net proceeds are funding internally
generated growth opportunities in Russia and Venezuela, further reductions of
debt, purchasing shares of our stock or other corporate purposes.

NOTE 4 - COMMITMENTS AND CONTINGENCIES

In July 2001, we entered into a three-year lease for office space in Houston,
Texas for approximately $11,000 per month. We also 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 the California office space has been
subleased for rents that approximate our lease costs.

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 in December 2001
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.
After the sale of our interest in Arctic Gas, the total market capitalization
and stockholders equity deficiencies were eliminated. As of June 30, 2002, we
were in compliance with the total market capitalization and stockholders' equity
standards.

On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against us and
Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas of Louisiana
("BOGLA"), seeking a determination that the sale by BOGLA to Tesla Resources
Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy Corporation, of
certain West Cote Blanche Bay properties for $15.1 million, constituted a
fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550 of the
Bankruptcy Code. In August 2001, a decision was rendered by the bankruptcy court
in BOGLA's favor denying any and all relief to the WRT Trust and granting BOGLA
its costs. WRT appealed the decision to the U.S. District Court for the Western
District of Louisiana. Recently, the parties reached an agreement in principle
to terminate the appeal and exchange mutual releases in return for a reduced
payment ($27,500) to BOGLA of its court awarded costs. We expect the settlement
to be concluded in the third quarter of 2002.

In the normal course of our business, we may periodically become subject to
actions threatened or brought by our investors or partners in connection with
the operation or development of our properties or the sale of securities. We are
also subject to ordinary litigation that is incidental to our business, none of
which is expected to have a material adverse effect on our financial position,
results of operations or liquidity.

NOTE 5 - TAXES

TAXES OTHER THAN ON INCOME
Benton-Vinccler pays municipal taxes on operating fee revenues it receives for
production from the South Monagas Unit. We have incurred the following
Venezuelan municipal taxes and other taxes (in thousands):

The six months ended June 30, 2002 included a non-recurring foreign payroll tax
adjustment of $0.7 million. The six months ended June 30, 2001 include an
adjustment to Venezuelan municipal taxes of $0.8 million due to a change in tax
rates at the South Monagas Unit in Venezuela.

TAXES ON INCOME
At December 31, 2001, we had, for federal income tax purposes, operating loss
carryforwards of approximately $130 million expiring in the years 2003 through
2020. It is anticipated that the entire $130 million will be utilized against
the gain from Arctic Gas Sale. We will not provide deferred tax assets on future
operating losses due to uncertainty of realization.

We do not provide deferred income taxes on undistributed earnings of
international consolidated subsidiaries for possible future remittances as all
such earnings are reinvested as part of our ongoing business.

12

NOTE 6 - OPERATING SEGMENTS

The Company regularly allocates resources to and assesses the performance of its
operations by segments that are organized by unique geographic and operating
characteristics. The segments are organized in order to manage regional
business, currency and tax related risks and opportunities. Revenues from the
Venezuela and United States operating segments are derived primarily from the
production and sale of oil. Operations included under the heading "United States
and other" include corporate management, exploration and production activities,
cash management and financing activities performed in the United States and
other countries which do not meet the requirements for separate disclosure. All
intersegment revenues, expenses and receivables are eliminated in order to
reconcile to consolidated totals. Corporate general and administrative and
interest expenses are included in the United States and other segment and are
not allocated to other operating segments.

13

NOTE 7 - RUSSIAN OPERATIONS

GEOILBENT

We own 34 percent of Geoilbent, a Russian limited liability company formed in
1991 that develops, produces and markets crude oil from the North Gubkinskoye
and South Tarasovskoye Fields in the West Siberia region of Russia. Our
investment in Geoilbent is accounted for using the equity method. Sales
quantities attributable to Geoilbent for the six months ended March 31, 2002 and
2001 were 3,552,795 barrels and 2,477,110 barrels, respectively. Prices for
crude oil for the six months ended March 31, 2002 and 2001 averaged $11.21 and
$19.08 per barrel, respectively. Depletion expense attributable to Geoilbent for
the six months ended March 31, 2002 and 2001 was $3.44 and $2.58 per barrel,
respectively due to lower reserves. Financial information for Geoilbent follows
(in thousands). All amounts represent 100 percent of Geoilbent.

(a) 2001 selling and distribution expenses were included in oil sales.

14

The European Bank for Reconstruction and Development ("EBRD") and International
Moscow Bank ("IMB") together agreed in 1996 to lend up to $65 million to
Geoilbent, based on achieving certain reserve and production milestones, under
parallel reserve-based loan agreements. In addition, the loan agreements require
that Geoilbent meet certain financial ratios and covenants, including a minimum
current ratio, and provides for certain limitations on liens, additional
indebtedness, certain investment and capital expenditures, dividends, mergers
and sales of assets. Under these loan agreements, we and the other shareholder
of Geoilbent have significant management and business support obligations. Each
shareholder is jointly and severally liable to EBRD and IMB for any losses,
damages, liabilities, costs, expenses and other amounts suffered or sustained
arising out of any breach by any shareholder of its support obligations.
Effective January 28, 2002, the interest rate for the loan was changed to
six-month LIBOR plus 4.75 percent. Principal payments are due in varying
installments on the semiannual interest payment dates beginning January 27, 2001
and ending by July 27, 2004. Geoilbent began borrowing under these facilities in
October 1997 and had borrowed a total of $48.5 million through January 31, 2002.
The proceeds from the loans were used by Geoilbent to develop the North
Gubkinskoye Field. Geoilbent has repaid $18.5 million of the loan through March
31, 2002. The principal payment requirements for the long-term debt of Geoilbent
at March 31, 2002 are as follows (in thousands):

2003 . . . . . . . . . . . . . . . . . . .$ 5,500
2004 . . . . . . . . . . . . . . . . . . . 11,000
-------
$16,500

On June 30, 2002, Geoilbent owed EBRD $27.5 million in total debt. Of this
amount, $5.5 million was paid on July 29, 2002. On June 30, 2002 Geoilbent owed
IMB $2.5 million in total debt. This amount was paid on July 29, 2002.

In May 2001, Geoilbent obtained a $3.3 million loan from IMB payable in six
payments of $0.6 million commencing August 1, 2001, ending November 1, 2002,
bearing interest at LIBOR plus 6.5 percent. The loan is collateralized by
moveable property in the South Tarasovskoye Field. On June 30, 2002, Geoilbent
had $1.1 million outstanding with IMB under this loan. Of this amount, $0.4
million was paid in July 2002, $0.2 million was paid on August 1, 2002 and the
balance is due in November 2002.

At June 30, 2002, Geoilbent had accounts payable outstanding of $25.4 million of
which approximately $8.5 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. As a
minority shareholder in Geoilbent, we are attempting to cause Geoilbent and its
majority shareholder to take the necessary steps to bring Geoilbent's payables
current with such creditors. These steps have included a reduced capital
expenditure budget. In June 2002, we loaned Geoilbent $2.5 million under a
subordinated loan agreement. The loan bears interest at six month LIBOR until
January 6, 2004, and the loan is due at that time. Payment is subordinated to
the EBRD facility. Geoilbent also received an $5.0 million loan from the other
shareholder. Proceeds from each loan were used to reduce accounts and taxes
payable. There can be no assurance that Geoilbent will have the ability to repay
the obligations when due. Involuntary bankruptcy would have no impact on cash
flow, as Geoilbent has not paid a dividend.

ARCTIC GAS COMPANY

In April 1998, we signed an agreement to earn a 40 percent equity interest in
Arctic Gas Company. Arctic Gas owns the exclusive rights to evaluate, develop
and produce the natural gas, condensate and oil reserves in the Samburg and
Yevo-Yakha license blocks in West Siberia. The two blocks comprise 794,972 acres
within and adjacent to the Urengoy Field, Russia's largest producing natural gas
field. Under the terms of a Cooperation Agreement between us and Arctic Gas, we
earned a 40 percent equity interest in exchange for providing or arranging for a
credit facility of up to $100 million for the project, the terms and timing of
which were finalized in February 2002. We received voting shares representing a
40 percent ownership in Arctic Gas that contain restrictions on their sale and
transfer. A Share Disposition Agreement provides for removal of the restrictions
as disbursements are made under the credit facility. From December 1998 through
December 2001, we purchased shares representing an additional 28 percent equity
interest not subject to any sale or transfer restrictions. On April 12, 2002, we
concluded the Arctic Gas Sale and transferred our 68% equity interest to the
buyer. The equity earnings of Arctic Gas have historically been based on a
calendar year ended September 30. The equity earnings for the first twelve days
of April will be included in the results for the third quarter of 2002.

15

Arctic Gas began selling oil in June 2000. All amounts represent 100 percent of
Arctic Gas. Summarized financial information for Arctic Gas follows (in
thousands):

(a) 2001 selling and distribution expenses were included in oil sales.

16

NOTE 8 - VENEZUELA OPERATIONS

On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), signed an operating service agreement to reactivate
and further develop three Venezuelan oil fields with Lagoven, S.A., then one of
three exploration and production affiliates of the national oil company,
Petroleos de Venezuela, S.A. ("PDVSA"). The operating service agreement covers
the South Monagas Unit. Under the terms of the operating service agreement,
Benton-Vinccler, a corporation owned 80 percent by us and 20 percent by
Vinccler, is a contractor for PDVSA and is responsible for overall operations of
the South Monagas Unit, including all necessary investments to reactivate and
develop the fields comprising the South Monagas Unit. Benton-Vinccler receives
an operating fee in U.S. dollars deposited into a U.S. commercial bank account
for each barrel of crude oil produced (subject to periodic adjustments to
reflect changes in a special energy index of the U.S. Consumer Price Index) and
is reimbursed according to a prescribed formula in U.S. dollars for its capital
costs, provided that such operating fee and cost recovery fee cannot exceed the
maximum dollar amount per barrel set forth in the agreement. The Venezuelan
government maintains full ownership of all hydrocarbons in the fields.

The stability of government in Venezuela and the government's relationship with
the state-owned national oil company, PDVSA, remain significant risks for our
company. PDVSA is the sole purchaser of all Venezuela oil production. On April
11, 2002, the President of Venezuela was removed from power as a result of a
civil and military coup. For a number of reasons, the interim government,
initially installed by the military, failed and the past president regained
power on April 13, 2002. Upon his return to power, the president named a new
president of PDVSA who, in turn, reinstated certain key PDVSA executives whom
the Venezuelan president had previously fired in February. These firings had
contributed to the political instability in the government and were cause for
concern for those companies doing business with PDVSA. During this period, our
oil production was not interrupted. However, it did delay the importation of
critical equipment, which contributed to the slowdown in our drilling
operations. The importance of PDVSA to Venezuela's future is utmost.
Accordingly, while no assurances can be given, we believe that PDVSA will
continue to operate and to purchase our oil production, and that the government
will work to minimize political uncertainty in order to continue to attract
foreign capital investment.

NOTE 9 - UNITED STATES OPERATIONS

We have a 35 percent working interest in the Lakeside Exploration Prospect,
Cameron Parish, Louisiana. One July 25, 2002, we spud the Claude Boudreaux #1
exploratory well on this prospect.

In March 1997, we acquired a 40 percent participation interest in three
California State offshore oil and gas leases ("California Leases") from Molino
Energy Company, LLC ("Molino Energy"), which held 100 percent of these leases.
The project area covers the Molino, Gaviota and Caliente Fields, located
approximately 35 miles west of Santa Barbara, California. Because we had no firm
approved plans to continue drilling on the California Leases and the 2199 #7
exploratory well did not result in commercial reserves, we wrote off all of the
capitalized costs associated with the California Leases of $9.2 million and the
joint interest receivable of $3.1 million due from Molino Energy at December 31,
1999.

NOTE 10 - CHINA OPERATIONS

In December 1996, we acquired Crestone Energy Corporation, a privately held
company headquartered in Denver, Colorado, subsequently renamed Benton Offshore
China Company. Its principal asset is a petroleum contract with China National
Offshore Oil Corporation ("CNOOC") for the WAB-21 area. The WAB-21 petroleum
contract covers 6.2 million acres in the South China Sea, with an option for an
additional 1.0 million acres under certain circumstances, and lies within an
area which is the subject of a territorial dispute between the People's Republic
of China and Vietnam. Vietnam has executed an agreement on a portion of the same
offshore acreage with Conoco Inc. The dispute has lasted for many years, and
there has been limited exploration and no development activity in the area under
dispute. 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 it
was determined because of the ongoing country dispute, and the inherent
exploration, and development and marketing risks associated with this project
required us to impair the undeveloped acreage by $13.4 million. The remaining
$2.9 million represents the value of the block based on various assumptions and
analgous public production profiles and plans.

NOTE 11 - RELATED PARTY TRANSACTIONS

From 1996 through 1998, we made unsecured loans to our then Chief Executive
Officer, A. E. Benton, bearing interest at the rate of 6 percent per annum. We
subsequently obtained a security interest in Mr. Benton's shares of our stock
and stock options. In August 1999, Mr. Benton filed a chapter 11
(reorganization) bankruptcy petition in the U.S. Bankruptcy Court for the
Central District of California, in Santa Barbara, California. In February 2000,
we entered into a separation agreement with Mr. Benton pursuant to which we
retained Mr. Benton under a consulting agreement to perform certain services for
us. In addition, the consulting agreement provided Mr. Benton with incentive
bonuses tied to our net cash receipts from the sale of our interests in Arctic
Gas and Geoilbent. We paid Mr. Benton a total of $536,545 from February 2000
through May 2001 for services performed under the consulting agreement, and in
June 2002, we made an estimated incentive bonus payment to Mr. Benton of $1.5
million in connection with the sale of our interest in Arctic Gas.

On May 11, 2001, Mr. Benton and the Company entered into a settlement and
release agreement under which the consulting agreement was terminated as to
future services and Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the repayment of our loans to him. Through the
settlement agreement we continue to retain our security interest in Mr. Benton's
600,000 shares of our stock and in his stock options, and we have the right to
vote the shares owned by him and to direct the exercise of his options. Under
the terms of the settlement agreement, repayment of our loans to Mr. Benton may
be achieved through Mr. Benton's liquidation of certain assets, disposition of
Mr. Benton's stock and stock options, and a portion of future income and any
incentive bonuses paid under the consulting agreement. In March 2002, Mr. Benton
filed a plan of reorganization in his bankruptcy case which incorporated the
terms of the settlement agreement. On July 31, 2002, the bankruptcy court
confirmed the plan of reorganization, and we expect the order to become final in
August 2002. The amount of Mr. Benton's indebtedness to us currently
approximates $6.7 million. We continue to accrue interest at the rate of 6
percent per annum and record additional allowances as the interest accrues.
Based upon information provided by Mr. Benton's bankruptcy counsel, we
anticipate that under the bankruptcy plan of reorganization we will receive a
cash payment of about $1.7 million from the liquidation of assets. While we can
provide no assurance, we believe that this cash payment, when coupled with the
value of our stock, the stock options and other proceeds payable by Mr. Benton,
will allow us to recover a significant portion of Mr. Benton's indebtedness to
us.

17

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

We caution you 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 our management involve risks and uncertainties and are subject to
change based on various important factors. When used in this report, the words
budget, budgeted, anticipate, expect, believes, goals or projects and similar
expressions are intended to identify forward-looking statements. In accordance
with the provisions of the Private Securities Litigation Reform Act of 1995, 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 price for oil and natural gas,
and other risks described in our filings with the Securities and Exchange
Commission. The following factors, among others, may in some cases have affected
our results and could cause actual results and plans for future periods to
differ materially from those expressed or implied in any such forward-looking
statements: fluctuations in oil and natural gas prices, changes in operating
costs, overall economic conditions, political stability, acts of terrorism,
currency and exchange risks, changes in existing or potential tariffs, duties or
quotas, availability of additional exploration and development opportunities,
availability of sufficient financing, changes in weather conditions, and ability
to hire, retain and train management and personnel. A discussion of these
factors is included in our 2001 Annual Report on Form 10-K, which includes
certain definitions and a summary of significant accounting policies and should
be read in conjunction with this Quarterly Report on Form 10-Q.

MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS

On April 12, 2002, we concluded the Arctic Gas Sale, on which we recognized a
gain of $143.1 million ($92.9 million after tax) in the three months ended June
30, 2002. On March 31, 2002, we used part of the proceeds to retire the entire
$108.0 million of 11.625 percent senior unsecured notes, and in April 2002, we
purchased $20.0 million (face value) of 9.375 percent senior unsecured notes for
$18.8 million plus accrued interest. A pre-tax gain of $0.9 million was
recognized on the purchase of these notes. These redemptions reduced our annual
interest expense by $14.5 million. Among the options under consideration for use
of the remaining net proceeds are funding internally generated growth
opportunities in Russia and Venezuela, further reductions of debt, purchasing
shares of our stock or other corporate purposes.

On May 14, 2002, the shareholders approved a change of our name to Harvest
Natural Resources, Inc. On July 15, 2002, Kerry R. Brittain joined the company
as our new Vice President, General Counsel and Corporate Secretary. Kerry brings
over 24 years of extensive experience in corporate and oil and gas law,
including serving as Vice President, General Counsel and Corporate Secretary for
Union Pacific Resources Group Inc. prior to its merger with Anadarko Petroleum
in 2000.

We possess significant producing assets in Venezuela and Russia. We believe that
the producing assets can be further optimized and the undeveloped acreage
exploited for further development. Our growth strategy is to access large
resources of hydrocarbons in Venezuela and Russia, to enable resource
development, to manage risk and to harvest value.

Current production from Geoilbent's North Gubkinskoye and South Tarasovskoye
Fields is approximately 17,300 barrels of oil per day. We believe the wells
drilled in the South Tarasovskoye Field in 2001 significantly increased the
value of our Russian properties and we are reviewing alternatives to maximize
their value. These alternatives include improved reservoir management, a
computer simulation study of the field, improved drilling and completion
practices, and construction of a natural gas processing facility. Geoilbent has
entered into negotiations with EBRD to increase the amount of its loan
commitment from the $22.0 million outstanding to a revolving facility of $50.0
million. EBRD has agreed in principal with the loan restructuring and the new
loan documents should be signed sometime in the third quarter. It is expected
that $8.0 million of the loan increase will be used to further reduce accounts
and taxes payable and $20.0 million will be applied to an 85-well development
program in the South Tarasovskoye Field. In addition to the EBRD restructuring,
we are working with the majority shareholder to take the necessary steps to
bring Geoilbent's payables current. These steps have included a reduction in the
2002 capital budget to approximately $16.6 million. In June, we loaned Geoilbent
$2.5 million under a subordinated loan agreement. The loan bears interest at
six-month LIBOR until January 6, 2004, and the loan is due at that time. Payment
is subordinated to the EBRD facility. Geoilbent also received a $5.0 million
loan from the other shareholder. Proceeds from each loan were used to reduce
accounts and taxes payable. There can be no assurance that Geoilbent will have
the ability to repay these obligations when due.

Oil production from the Company's South Monagas Unit in Venezuela was virtually
flat with last year's production at 2.5 million barrels (27,700 bopd) for the
three months ended June 30, 2002. The Company is reducing its 2002 production
guidance by 10

18

percent to 28,000 to 30,000 barrels of oil per day from the South
Monagas Unit. The revised production profile is due to delays in the completion
of additional water handling capacity at the Tucupita plant and in the Tucupita
drilling program as a result of heavy rains. For the balance for the year, we
will increase the South Monagas Unit capital expenditures program up to $11.4
million to approximately $42.5 million. We are evaluating the construction of
additional processing and handling facilities and are in discussions with PDVSA
to negotiate a gas sales contract that will allow for the first time sale of
natural gas in Venezuela by our affiliate.

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.
Accordingly, our results of operations for the six months ended June 30, 2002
and 2001 reflect results from Geoilbent and Arctic Gas for the six months ended
March 31, 2002 and 2001, respectively.

We follow the full-cost method of accounting for our investments in oil and gas
properties. We capitalize all acquisition, exploration, and development costs
incurred. We account for our oil and gas properties using cost centers on a
country by country basis. We credit proceeds from sales of oil and gas
properties to the full-cost pools if the sales do not result in a significant
change in the relationship between costs and the value of proved reserves or the
underlying value of unproved property. We amortize capitalized costs of oil and
gas properties within the cost centers on an overall unit-of-production method
using proved oil and gas reserves as audited or prepared by independent
petroleum engineers. Costs that we amortize include:

o all capitalized costs (less accumulated amortization and impairment);

o the estimated future expenditures (based on current costs) to be
incurred in developing proved reserves; and

o estimated dismantlement, restoration and abandonment costs (see Note
1 of the "Notes to the Consolidated Financial Statements" for
additional information).

You should read the following discussion of the results of operations for the
three and six months ended June 30, 2002 and 2001 and the financial condition as
of June 30, 2002 and December 31, 2001 in conjunction with our Consolidated
Financial Statements and related Notes thereto included in PART I, Item 1,
"Financial Statements."

THREE MONTHS ENDED JUNE 30, 2002 AND 2001

Our revenues increased $0.2 million, or 1 percent, during the three months ended
June 30, 2002 compared with 2001. This was due to increased oil sales revenue in
Venezuela as a result of increased sales quantities, partially offset by
decreases in world crude oil prices. Our sales quantities for the three months
ended June 30, 2002 from Venezuela were 2.5 million barrels (27,100 barrels of
oil per day) compared with 2.4 million barrels (26,400 barrels of oil per day)
for the three months ended June 30, 2001. The increase in sales quantities of
69,000 barrels, or 3 percent, was due primarily to our Tucupita drilling
program. Prices for crude oil averaged $13.37 per barrel (pursuant to terms of
an operating service agreement) from Venezuela during the three months ended
June 30, 2002 compared with $13.68 per barrel during the three months ended June
30, 2001.

Our operating expenses decreased $1.2 million, or 14 percent, during the three
months ended June 30, 2002 compared with the three months ended June 30, 2001.
This was primarily due to reduced transportation costs, workovers and the
devaluation of Bolivar based expenditures at the South Monagas Unit in
Venezuela. Operating expenses during the three months ended June 30, 2002
compared with the same period of 2001 were $3.42 per barrel and $4.02 per
barrel, respectively. We anticipate that operating expenses at the South Monagas
Unit will average between $3.00 and $3.50 per barrel in 2002. Depletion,
depreciation and amortization increased $0.5 million, or 7 percent, during the
three months ended June 30, 2002 compared with 2001 primarily due to increased
oil production, decreased proved reserves and increased future development costs
at the South Monagas Unit. Depletion expense per barrel of oil produced from
Venezuela during the three months ended June 30, 2002 was $2.37 compared with
$2.12 during 2001.

We recognized write-downs of $13.4 million and $0.4 million at June 30, 2002 and
2001, respectively, for the impairment of the China WAB-21 block in the three
months ended June 30, 2002 as well as of capitalized costs associated with
exploration prospects in both periods. Total general and administrative expenses
decreased $0.4 million, or 7 percent, during the three months ended June 30,
2002 as compared with 2001. Increases in general and administrative expenses in
the three months ended June 30, 2002 were for performance bonuses ($1.1
million), legal and insurance costs ($0.4 million), severance and stock option
vesting acceleration ($0.6 million), and other miscellaneous expenses ($0.2
million). These increases are less than the general and administrative expenses
incurred in the three months ended June 30, 2001 for the reduction in force
($1.2 million), underwriting fees to amend indenture covenants ($1.1 million),
and the inability to capitalize exploration overhead and reduced office rent
($0.4 million).

19

Taxes other than on income decreased $0.7 million, or 60 percent, during the
three months ended June 30, 2002 compared with the three months ended June 30,
2001.

Investment income and other increased $0.3 million, or 23 percent, during the
three months ended June 30, 2002 compared with 2001, primarily due to lower
interest rates on higher marketable securities balances due to the Arctic Gas
Sale. Interest expense decreased $1.7 million, or 37 percent, during the three
months ended June 30, 2002 compared with 2001. This was primarily due to the
redemption of the 2003 senior unsecured notes and the purchase of $20 million
2007 senior unsecured notes. Net gain on exchange rates increased $2.2 million
for the three months ended June 30, 2002 compared with 2001 due to changes in
the value of the Bolivar and increased net monetary liabilities denominated in
Bolivars. We realized income before income taxes and minority interest of $140.2
million during the three months ended June 30, 2002 compared with income of $3.2
million in 2001. This resulted in increased income tax expense of $55.8 million.
The effective tax rate of 43 percent varies from the U.S. statutory rate of 35
percent primarily as a result of an increase in the valuation allowance for net
operating losses generated in 2002 that are not expected to be realized in the
future, adjustments to the prior year estimated net operating loss, and the tax
effect of the write-off of the China WAB-21 block, for which there is no
expected tax benefit. The income attributable to the minority interest increased
$0.5 million for the three months ended June 30, 2002 compared with 2001. This
was primarily due to the increased profitability of Benton-Vinccler.

Equity in net earnings of affiliated companies decreased $3.2 million during the
three months ended June 30, 2002 compared with 2001. This was primarily due to
the increased loss from Geoilbent and Arctic Gas. Our share of revenues from
Geoilbent was $4.8 million for the three months ended March 31, 2002 compared
with revenues of $6.7 million for 2001. The decrease of $1.9 million, or 38
percent, was due to lower world crude oil prices partially offset by increased
sales quantities. Prices for Geoilbent's crude oil averaged $8.68 per barrel
during the three months ended March 31, 2002 compared with $16.42 per barrel for
the three months ended March 31, 2001. Our share of Geoilbent oil sales
quantities increased by 149,643 barrels, or 27 percent, from 557,302 barrels
sold during the three months ended March 31, 2002 to 407,659 barrels sold during
the three months ended March 31, 2001.

SIX MONTHS ENDED JUNE 30, 2002 AND 2001

Our revenues decreased $6.9 million, or 11 percent, during the six months ended
June 30, 2002 compared with 2001. This was due to decreased oil sales revenue in
Venezuela as a result of a decrease in world crude oil prices. Our sales
quantities for the six months ended June 30, 2002 from Venezuela were 5.0
million barrels (27,500 barrels of oil per day) compared with 5.0 million
barrels for the six months ended June 30, 2001. Normal volume declines in
existing wells were offset by new production under the Tucupita Field
development. Prices for crude oil averaged $12.03 per barrel (pursuant to terms
of an operating service agreement) from Venezuela during the six months ended
June 30, 2002 compared with $13.51 per barrel during the six months ended June
30, 2001.

Our operating expenses decreased $6.7 million, or 42 percent, during the six
months ended June 30, 2002 compared with the six months ended June 30, 2001.
This was primarily due to decreased workover costs and the devaluation of
Bolivar based expenditures. Operating expenses during the six months ended June
30, 2002 compared with the same period of 2001 were $3.17 per barrel and $4.52
per barrel, respectively. Depletion, depreciation and amortization increased
$2.1 million, or 14 percent, during the six months ended June 30, 2002 compared
with 2001 primarily due to increased oil production, decreased proved reserves
and increased future development costs at the South Monagas Unit. Depletion
expense per barrel of oil produced from Venezuela during the six months ended
June 30, 2002 was $2.37 compared with $2.12 during 2001.

We recognized write-downs of $13.4 million and $0.4 million at June 30, 2002 and
2001, respectively, for the impairment of the China WAB-21 block in the three
months ended June 30, 2002 as well as of capitalized costs associated with
exploration prospects in both periods. General and administrative expenses
decreased $1.8 million, or 21 percent, during the six months ended June 30, 2002
compared with 2001. Increases in general and administrative expenses in the six
months ended June 30, 2002 were for performance bonuses ($1.1 million), legal
and insurance costs ($0.6 million), and other miscellaneous expenses ($0.4
million). These increases are less than the general and administrative expenses
incurred in the six months ended June 30, 2001 for severance and stock option
vesting acceleration ($0.3 million), the reduction in force ($1.9 million),
underwriting fees to amend indenture covenants ($1.1 million), inability to
capitalize exploration overhead, and reduced office rent and sublease income
($0.6 million). Taxes other than on income decreased $1.3 million, or 73
percent, during the six months ended June 30, 2002 compared with the six months
ended June 30, 2001 primarily due to one-time municipal tax adjustments due to a
change in tax rates at the South Monagas Unit in Venezuela.

Investment income and other decreased slightly, during the six months ended June
30, 2002 compared with 2001, primarily due to lower average interest rates and
higher marketable securities balances due to the Arctic Gas Sale. Interest
expense decreased $1.3 million, or 12 percent, during the six months ended June
30, 2002 compared with 2001. This was primarily due to redemption of the 2003
senior unsecured notes and the purchase of $20 million 2007 senior unsecured
notes. Net gain on exchange rates increased $4.2 million for the six months
ended June 30, 2002 compared with 2001. This was due to changes in the value of
the Bolivar and increased net monetary liabilities denominated in Bolivars. We
realized income before income taxes

20

and minority interests of $144.8 million during the six months ended June 30,
2002 compared with income of $7.6 million in 2001. This resulted in increased
income tax expense of $54.4 million. The effective tax rate of 43 percent varies
from the U.S. statutory rate of 35 percent primarily as a result of an increase
in the valuation allowance for net operating losses generated in 2002 that are
not expected to be realized in the future, adjustments to the prior year
estimated net operating loss, and the tax effect of the write-off of the China
WAB-21 block, for which there is no expected tax benefit. The income
attributable to the minority interest increased $0.6 million for the six months
ended June 30, 2002 compared with 2001. This was primarily due to the increased
profitability of Benton-Vinccler.

Equity in net earnings of affiliated companies decreased $5.6 million during the
six months ended June 30, 2002 compared with 2001. This was primarily due to the
increased losses from Geoilbent and Arctic Gas. Our share of revenues from
Geoilbent was $13.5 million for the six months ended March 31, 2002 compared
with revenues of $16.1 million for 2001. The decrease of $2.5 million, or 19
percent, was due to significantly lower Russian domestic crude oil prices
partially offset by increased sales quantities. Prices for Geoilbent's crude oil
averaged $11.21 per barrel during the six months ended March 31, 2002 compared
with $19.08 per barrel for the six months ended March 31, 2001. Our share of
Geoilbent oil sales quantities increased by 365,053 barrels, or 30 percent, from
1,207,950 barrels sold during the six months ended March 31, 2002 to 842,897
barrels sold during the six months ended March 31, 2001.

NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002. We are currently
assessing the impact of SFAS No. 143 and therefore, at this time, cannot
reasonably estimate the effect of this statement on its consolidated financial
position, results of operations or cash flows.

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

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

CAPITAL RESOURCES AND LIQUIDITY

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

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

o geological, geophysical and seismic costs; and

o acquisition of interests in oil and gas properties.

The amount of available capital will affect the scope of our operations and the
rate of our growth. As of June 30, 2002, our cash and marketable securities
balance was $69.6 million. Our future rate of growth also depends substantially
upon the prevailing prices of oil. Prices also affect the amount of cash flow
available for capital expenditures and our ability to service our debt.
Additionally, our ability to pay interest on our debt and general corporate
overhead is dependent upon the ability of Benton-Vinccler and Geoilbent to make
loan repayments, dividend and other cash payments to us; however, there may be
contractual obligations or legal impediments to receiving dividends or
distributions from our subsidiaries.

Debt Reduction and Restructuring Program. We currently have significant debt
principal obligations payable in 2007 ($85 million). We may pursue additional
open market debt purchases of the obligations due in 2007 to further reduce the
debt.

21

Working Capital. Our capital resources and liquidity are affected by the timing
of our semiannual interest payments of approximately $4.0 million each May 1 and
November 1 and by the quarterly payments from PDVSA at the end of the months of
February, May, August and November pursuant to the terms of the contract between
Benton-Vinccler and PDVSA. As a consequence of the timing of these interest
payment outflows and the PDVSA payment inflows, our cash balances can increase
and decrease dramatically on a few dates during the year. In each May and
November in particular, interest payments at the beginning of the month and
PDVSA payments at the end of the month create large swings in our cash balances.
We have an uncommitted short-term working capital facility of 13 billion
Bolivars, (approximately $10 million at June 30, 2002), available to
Benton-Vinccler by a Venezuelan commercial bank. The credit facility bears
interest at fixed rates for 30-day periods, is guaranteed by us and contains no
restrictive or financial ratio covenants. We believe that similar arrangements
will be available to us in future quarters. At June 30, 2002, there was no
outstanding balance. In February 2002, the Venezuelan Bolivar was allowed to
float against the U.S. dollar, resulting in a significant devaluation of the
Bolivar. While the long-term impact of this action is uncertain, the short-term
implication may be difficulty in purchasing U.S. dollars with Bolivars and
reducing U.S. dollar equivalent amounts of Benton-Vinccler's short-term working
capital facility. We are negotiating with a bank to replace the short-term
working capital facility with a $15 million project financing to fund certain
infrastructure improvements. We do not expect this action to have a material
impact on Benton-Vinccler's operations.

Among the options under consideration for use of the remaining net proceeds are
funding internally generated growth opportunities in Russia and Venezuela,
further reductions of debt, purchasing shares of our stock or other corporate
purposes. We continue to develop sources of additional capital and management of
our cash requirements by various techniques including, but not limited to:

o managing the scope and timing of our capital expenditures,
substantially all of which are within our discretion;

o forming joint ventures or alliances with financial or other industry
partners;

o possible future hedging price risks and;

o monetizing assets.

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

At June 30, 2002, we had current assets of $111.9 million and current
liabilities of $46.7 million, resulting in working capital of $65.2 million and
a current ratio of 2.4 to 1. This compares with a negative working capital of
$0.6 million and a negative current ratio at December 31, 2001. The increase in
working capital of $65.8 million was primarily due to the Arctic Gas Sale.

At June 30, 2002, Geoilbent had accounts payable outstanding of $25.4 million of
which approximately $8.5 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, for which payments are 90
days or more past due, can force a company into involuntary bankruptcy. As a
minority shareholder in Geoilbent, we are attempting to cause Geoilbent and its
majority shareholder to take the necessary steps to bring Geoilbent's payables
current with such creditors. These steps have included a reduced capital
expenditure budget. In June 2002, we loaned Geoilbent $2.5 million under a
subordinated loan agreement. The loan bears interest at six-month LIBOR until
January 6, 2004, and the loan is due at that time. Payment is subordinated to
the EBRD facility. Geoilbent also received an additional $5.0 million from a
loan from the other shareholder. Proceeds from each loan were used to reduce
accounts and taxes payable. There can be no assurance that Geoilbent will have
the ability to repay its obligations when due. Involuntary bankruptcy would have
no impact on cash flow, as Geoilbent has not paid a dividend.

Cash Flow from Operating Activities. During the six months ended June 30, 2002
and 2001, net cash provided by operating activities was approximately $11.9
million and $24.0 million, respectively. Cash flow from operating activities
decreased by $12.1 million during the six months ended June 30, 2002 compared
with 2001. This was primarily due to increased collections of accrued revenues
and reduced interest payments which were substantially offset by a reduction in
accounts payable, restructuring charges of $0.9 million associated with the
reduction in force and corporate restructuring plan adopted in June 2001 and
legal and professional fees of $1.0 million associated with the offer to
restructure our senior notes due May 1, 2003.

22

Cash Flow from Investing Activities. A $189.8 million payment was received on
the Arctic Gas Sale. During the six months ended June 30, 2002 and 2001, we had
drilling and production related capital expenditures of approximately $20.7
million and $22.2 million, respectively, related to the South Monagas Unit.

We expect capital expenditures of approximately $42.5 million for calendar year
2002, including the $11.4 million revision substantially all of which will be at
the South Monagas Unit. The timing and size of the investments for the South
Monagas Unit is substantially at our discretion. We anticipate that Geoilbent
will continue to fund its expenditures through its own cash flow, the $7.5
million loans from its shareholders, and credit facilities. Our remaining
capital commitments worldwide are relatively minimal and are substantially at
our discretion. We will also be required to make interest payments of
approximately $8 million related to our outstanding senior notes during the next
12 months.

Cash Flow from Financing Activities. In November 1997, we issued $115 million in
9.375 percent senior unsecured notes due November 1, 2007, of which we
subsequently repurchased $30 million for cash. Interest on all of the notes is
due May 1 and November 1 of each year. The indenture agreement provides for
certain limitations on liens, additional indebtedness, certain investment and
capital expenditures, dividends, mergers and sales of assets. At June 30, 2002,
we were in compliance with all covenants of the indenture.

In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan
commercial bank, in the form of two loans, for construction of a 31-mile oil
pipeline that will connect the Tucupita Field production facility with the
Uracoa central processing unit. The first loan, in the amount of $6 million,
bears interest payable monthly based on 90-day LIBOR plus 5 percent (7.04
percent at June 30, 2002) with principal payable quarterly for five years. The
second loan, in the amount of 4.4 billion Venezuelan Bolivars (approximately
$6.3 million), bears interest payable monthly based on a mutually agreed
interest rate determined quarterly or a 6-bank average published by the central
bank of Venezuela. The Bolivar interest rate at June 30, 2002 was 58 percent or
a negative percent in U.S. dollar terms for the quarter due to the Bolivar
devaluation.

DOMESTIC OPERATIONS

One July 25, 2002, we spud the Claude Boudreaux #1 exploratory well on this
prospect. We have a 35 percent working interest in the Lakeside Exploration
Prospect, Cameron Parish, Louisiana.

In March 1997, we acquired a 40 percent participation interest in three
California State offshore oil and natural gas leases ("California Leases") from
Molino Energy Company, LLC ("Molino Energy"), which held 100 percent of these
leases. The project area covers the Molino, Gaviota and Caliente Fields, located
approximately 35 miles west of Santa Barbara, California. Because we had no firm
approved plans to continue drilling on the California Leases and the 2199 #7
exploratory well did not result in commercial reserves, we wrote off all of the
capitalized costs associated with the California Leases of $9.2 million and the
joint interest receivable of $3.1 million due from Molino Energy at December 31,
1999.

INTERNATIONAL OPERATIONS

On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), signed an operating service agreement to reactivate
and further develop three Venezuelan oil fields with an affiliate of the
national oil company, Petroleos de Venezuela, S.A. ("PDVSA"). The operating
service agreement covers the South Monagas Unit. Under the terms of the
operating service agreement, Benton-Vinccler, a corporation owned 80 percent by
us and 20 percent by Vinccler, is a contractor for PDVSA and is responsible for
overall operations of the Unit South Monagas, 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 December 1996, we acquired Crestone Energy Corporation, a privately held
company headquartered in Denver, Colorado, subsequently renamed Benton Offshore
China Company. Its principal asset is a petroleum contract with China National
Offshore Oil Corporation ("CNOOC") for the WAB-21 area. The WAB-21 petroleum
contract covers 6.2 million acres in the South China Sea, with an option for an
additional 1.0 million acres under certain circumstances, and lies within an
area which is the subject of a territorial dispute between the People's Republic
of China and Vietnam. Vietnam has executed an agreement on a portion of the same
offshore acreage with Conoco Inc. The dispute has lasted for many years, and
there has been limited exploration and no development activity in the area under
dispute. 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,
it was determined, because of the ongoing country dispute, and the inherent
exploration, and development marketing risks associated with this project
required us to impair the undeveloped acreage by $13.4 million. The remaining
$2.9 million represents the value of the block based on various assumptions and
analogous public production profiles and plans.

23

On April 12, 2002, we completed the Arctic Gas Sale. The equity earnings of
Arctic Gas have historically been based on a calendar year ended September 30.
The equity earnings for the first twelve days of April will be included in the
third calendar quarter of 2002. This amount is not expected to be material.

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

o Harvest owns 34 percent;

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

In November 1993, the agreement was registered with the Russian Agency for
International Cooperation and Development. Geoilbent was later re-chartered as a
limited liability company. We believe that we have developed a good relationship
with the other Geoilbent shareholder and have not experienced any disagreements
on major operational matters. We are reviewing ways to improve the operations,
but we are a minority partner. Geoilbent shareholder action requires a 67
percent majority vote of its shareholders.

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

The North Gubinskoye field is included inside a license block of 167,086 acres,
an area approximately 15 miles long and four miles wide. The field has been
delineated with over 60 exploratory wells, which tested 26 separate reservoirs.
The field is a large anticlinal structure with multiple pay sands. The
development to date has focused on the BP 8, 9, 10, 11 and 12 reservoirs with
minor development in the BP 6 and 7 reservoirs. Geoilbent is currently flaring
the produced natural gas in accordance with environmental regulations, although
it is exploring alternatives to market the natural gas.

The South Tarasovskoye Field is located a few miles southeast of North
Gubinskoye field and straddles the eastern boundary of the Urabor Yakhinsky
exploration block acquired by Geoilbent in 1998. It is estimated a majority of
the field is situated within the block. The remaining portion of the field falls
within a license block owned by Purneftegaz. Production began in early 2001 from
a discovery well drilled close to the boundary by Purneftegaz. Only 521 of
Geoilbent's 763,558 acres in this field are reflected as proved-developed acres.
Geoilbent also holds rights to two more license blocks comprising 426,199 acres.

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 ($15.00 to $25.00 per barrel), 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 $25.48 per ton, plus a tariff of 40
percent on the sum exceeding $182.50. We are unable to predict the impact of
taxes, duties and other burdens for the future on our Russian operations. The
Russian government will again raise the export tariff beginning August 1, 2002
to $21.90 per ton ($3.00 per barrel) due to the rise in oil prices over the last
several months.

EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION

Our results of operations and cash flow are affected by changing oil prices.
However, our South Monagas Unit oil sales are based on a fee adjusted quarterly
by the percentage change of a basket of crude oil prices instead of by absolute
dollar changes. This dampens both any upward and downward effects of changing
prices on our Venezuelan oil sales and cash flows. If the price of oil
increases, there could be an increase in our cost for drilling and related
services because of increased demand, as well as an increase in oil sales.
Fluctuations in oil and natural gas prices may affect our total planned
development activities and capital expenditure program. There are presently no
restrictions in either Venezuela or Russia that restrict converting U.S. dollars
into local currency. However, from June 1994 through April 1996, Venezuela
implemented exchange controls which significantly limited the ability to convert
local currency into U.S. dollars. Because payments to Benton-Vinccler are made
in U.S. dollars into its United States bank account, and Benton-Vinccler is not
subject to regulations requiring the conversion or repatriation of those dollars
back into Venezuela, the exchange controls did not have a material adverse
effect on us or Benton-Vinccler. Currently, there are no exchange controls in
Venezuela or Russia that restrict conversion of local currency into U.S. dollars
for routine business operations, such as the payments of invoices, debt
obligations and dividends.

Within the United States, inflation has had a minimal effect on us, but it is
potentially an important factor in results of operations in Venezuela and
Russia. With respect to Benton-Vinccler and Geoilbent, a significant majority of
the sources of funds, including the proceeds from oil sales, our contributions
and credit financings, are denominated in U.S. dollars, while local transactions
in Russia and Venezuela are conducted in local currency. If the rate of increase
in the value of the dollar compared

24

to the bolivar continues to be less than the rate of inflation in Venezuela,
then inflation could be expected to have an adverse effect on Benton-Vinccler.

During the six months ended June 30, 2002, net foreign exchange gains
attributable to our Venezuelan operations were $4.4 million and net foreign
exchange gains attributable to our Russian operations were $0.7 million.
However, there are many factors affecting foreign exchange rates and resulting
exchange gains and losses, many of which are beyond our control. We have
recognized significant exchange gains and losses in the past, resulting from
fluctuations in the relationship of the Venezuelan and Russian currencies to the
U.S. dollar. It is not possible for us to predict the extent to which we may be
affected by future changes in exchange rates and exchange controls.

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 price controls, tax and other laws
relating to the petroleum industry, by changes in such laws and by changing
administrative regulations and the interpretations and application of such rules
and regulations. In addition, various federal, state, local and international
laws and regulations covering the discharge of materials into the environment,
the disposal of oil and natural gas wastes, or otherwise relating to the
protection of the environment, may affect our operations and results.

CONCLUSION

While we can give you no assurance, we currently believe that our capital
resources and liquidity will be adequate to fund our planned capital
expenditures, investments in and advances to affiliates, and semiannual interest
payment obligations for the next 12 months. Our expectation is based upon cash
and marketable securities on hand and our current estimate of projected price
levels, production and the availability of short-term working capital facilities
of up to $10 million during the time periods between the submission of quarterly
invoices to PDVSA by Benton-Vinccler and the subsequent payments of these
invoices by PDVSA. Actual results could be materially affected if there is a
significant decrease in either price or production levels related to the South
Monagas Unit. Future cash flows are subject to a number of variables including,
but not limited to, the level of production and prices, as well as various
economic conditions that have historically affected the oil and natural gas
business. Prices for oil are subject to fluctuations in response to changes in
supply, market uncertainty and a variety of factors beyond our control. We
estimate that a change in the price of oil of $1.00 per barrel would affect cash
flow from operations by approximately $1.2 million based on our second quarter
production rates and cost structure.

25

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

OIL AND NATURAL GAS PRICES

As an independent oil and natural gas producer, our revenue, other income and
equity earnings and profitability, reserve values, access to capital and future
rate of growth are substantially dependent upon the prevailing prices of crude
oil and condensate. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond our control. Historically, prices received
for oil and natural gas production have been volatile and unpredictable, and
such volatility is expected to continue. This volatility is demonstrated by the
average realizations in Venezuela, which declined from $10.01 per barrel in 1997
to $6.75 in 1998, increased to $14.94 in 2000, decreased to $12.52 in 2001 and
averaged $12.03 in the first six months of 2002. Based on our budgeted
production and costs, we will require an average realization in Venezuela of
approximately $8.64 per barrel in 2002 in order to break-even on income from
consolidated companies before our equity in earnings from affiliated companies.
From time to time, we have utilized hedging transactions with respect to a
portion of our oil and natural gas production to achieve a more predictable cash
flow, as well as to reduce our exposure to price fluctuations, but we have
utilized no such transactions since 1996. While hedging limits the downside risk
of adverse price movements, it may also limit future revenues from favorable
price movements. Because gains or losses associated with hedging transactions
are included in oil sales when the hedged production is delivered, such gains
and losses are generally offset by similar changes in the realized prices of the
commodities. We did not enter into any commodity hedging agreements during the
six months ended June 30, 2002 or 2001.

INTEREST RATES

Total long-term debt at June 30, 2002 of $90.2 million consisted of fixed-rate
senior unsecured notes maturing in 2007 ($85.3 million) and $4.9 million of
floating-rate notes due in 2006. A hypothetical 10 percent adverse change in the
floating rate would not have had a material affect on our results of operations
for the six months ended June 30, 2002.

FOREIGN EXCHANGE

Our operations are located primarily outside of the United States. In
particular, our current oil producing operations are located in Venezuela and
Russia, countries which have had recent histories of significant inflation and
devaluation. For the Venezuelan operations, oil sales are received under a
contract in effect through 2012 in U.S. dollars; expenditures are both in U.S.
dollars and local currency. For the Russian operations, a majority of the oil
sales are received in Rubles; expenditures are both in U.S. dollars and local
currency, although a larger percentage of the expenditures are in local
currency. We have utilized no currency hedging programs to mitigate any risks
associated with operations in these countries, and therefore our financial
results are subject to favorable or unfavorable fluctuations in exchange rates
and inflation in these countries.

POLITICAL RISK

The stability of government in Venezuela and the government's relationship with
the state-owned national oil company, PDVSA, remain significant risks for our
company. PDVSA is the sole purchaser of all Venezuela oil production. On April
11, 2002, the President of Venezuela was removed from power as a result of a
civil and military coup. For a number of reasons, the interim government,
initially installed by the military, failed and the past president regained
power on April 13, 2002. Upon his return to power, the president named a new
president of PDVSA who, in turn, reinstated certain key PDVSA executives who in
the Venezuelan president had previously fired in February. These firings had
contributed to the political instability in the government and were cause for
concern for those companies doing business with PDVSA. During this period, our
oil production was not interrupted. However, it did delay the importation of
critical equipment which contributed to the slowdown in our drilling operations.
The importance of PDVSA to Venezuela's future is utmost. PDVSA supplies 50
percent of all government revenues, 33 percent of Gross Domestic Product and 75
percent of total exports. Accordingly, while no assurances can be given, we
believe that PDVSA will continue to operate and to purchase our oil production,
and that the government will work to minimize political uncertainty in order to
continue to attract foreign capital investment.

26

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

WRT Litigation

On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against us and
Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas of Louisiana
("BOGLA"), seeking a determination that the sale by BOGLA to Tesla Resources
Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy Corporation, of
certain West Cote Blanche Bay properties for $15.1 million, constituted a
fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550 of the
Bankruptcy Code. In August 2001, a decision was rendered by the bankruptcy court
in BOGLA's favor denying any and all relief to the WRT Trust and granting BOGLA
its costs. WRT appealed the decision to the U.S. District Court for the Western
District of Louisiana. Recently, the parties reached an agreement in principle
to terminate the appeal and exchange mutual releases in return for a reduced
payment ($27,500) to BOGLA of its court awarded costs. We expect the settlement
to be concluded in the third quarter of 2002.

A. E. Benton Reorganization

From 1996 through 1998, we made unsecured loans to our then Chief Executive
Officer, A. E. Benton, bearing interest at the rate of 6 percent per annum. We
subsequently obtained a security interest in Mr. Benton's shares of our stock
and stock options. In August 1999, Mr. Benton filed a chapter 11
(reorganization) bankruptcy petition in the U.S. Bankruptcy Court for the
Central District of California, in Santa Barbara, California. In February 2000,
we entered into a separation agreement with Mr. Benton pursuant to which we
retained Mr. Benton under a consulting agreement to perform certain services for
us. In addition, the consulting agreement provided Mr. Benton with incentive
bonuses tied to our net cash receipts from the sale of our interests in Arctic
Gas and Geoilbent. We paid Mr. Benton a total of $536,545 from February 2000
through May 2001 for services performed under the consulting agreement, and in
June 2002, we made an estimated incentive bonus payment to Mr. Benton of $1.5
million in connection with the sale of our interest in Arctic Gas.

On May 11, 2001, Mr. Benton and the Company entered into a settlement and
release agreement under which the consulting agreement was terminated as to
future services and Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the repayment of our loans to him. Through the
settlement agreement we continue to retain our security interest in Mr. Benton's
600,000 shares of our stock and in his stock options, and we have the right to
vote the shares owned by him and to direct the exercise of his options. Under
the terms of the settlement agreement, repayment of our loans to Mr. Benton may
be achieved through Mr. Benton's liquidation of certain assets, disposition of
Mr. Benton's stock and stock options, and a portion of future income and any
incentive bonuses paid under the consulting agreement. In March 2002, Mr. Benton
filed a plan of reorganization in his bankruptcy case which incorporated the
terms of the settlement agreement. On July 31, 2002, the bankruptcy court
confirmed the plan of reorganization, and we expect the order to become final in
August 2002. The amount of Mr. Benton's indebtedness to us currently
approximates $6.7 million. We continue to accrue interest at the rate of 6
percent per annum and record additional allowances as the interest accrues.
Based upon information provided by Mr. Benton's bankruptcy counsel, we
anticipate that under the bankruptcy plan of reorganization we will receive a
cash payment of about $1.7 million from the liquidation of assets. While we can
provide no assurance, we believe that this cash payment, when coupled with the
value of our stock, the stock options and other proceeds payable by Mr. Benton,
will allow us to recover a significant portion of Mr. Benton's indebtedness to
us.

ITEM 2. CHANGES IN SECURITIES
None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.

27

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

At our Annual Meeting of Stockholders held on May 14, 2002,
the following items were voted on by the Stockholders:

1. To approve the Election of Directors:

2. To ratify the appointment of PricewaterhouseCoopers
LLP as the independent accountants for the year
ended December 31, 2002:

3. To approve the Amended and Restated Certificate of
Incorporation to incorporate previously adopted
amendments and to change the name of the company to
"Harvest Natural Resources, Inc.":

ITEM 5. OTHER INFORMATION
None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits

3.1(i) Amended and Restated Certificate of
Incorporation of Benton Oil and Gas
Company.
3.1(ii) Restated Bylaws as of May 14, 2002.
4.1 Rights Agreement between Benton Oil and Gas
Company and First Interstate Bank,
Rights Agent dated April 28, 1995.
10.2 Subordinated Loan Agreement US$2,500,000
between Limited Liability Company
"Geoilbent" as borrower, and Harvest
Natural Resources, Inc. as lender.
10.3 See 4.1 above.

(b) Reports on Form 8-K

One April 9, 2002, we filed a report on the sale of our
interest in Arctic Gas Company on Form 8-K under Item 2,
"Acquisition or Disposition of Assets", and Item 7(b),
"Financial Statements and Exhibits - Pro Forma Financial
Information".

28

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

HARVEST NATURAL RESOURCES, INC.

Dated: August 13, 2002 By: /s/Peter J. Hill
----------------
Peter J. Hill
President and Chief Executive Officer

Dated: August 13, 2002 By: /s/Steven W. Tholen
-------------------
Steven W. Tholen
Senior Vice President of Finance
and Administration and Chief
Financial Officer

29

ACCOMPANYING CERTIFICATE
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Not Filed Pursuant to the Securities Exchange Act of 1934

The undersigned Chief Executive Officer and Chief Financial Officer of Harvest
Natural Resources, Inc. (the "Company") do hereby certify as follows:

Solely for the purpose of meeting the apparent requirements of Section 906 of
the Sarbanes-Oxley Act of 2002, and solely to the extent this certification may
be applicable to this Quarterly Report on Form 10-Q, the undersigned hereby
certify that this Quarterly Report on Form 10-Q fully complies with the
requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934
and the information contained in this Report on Form 10-Q fairly presents, in
all material respects, the financial condition and results of operations of the
Company.

Dated: August 13, 2002 By: /s/ Peter J. Hill
-----------------
Peter J. Hill
President and Chief Executive Officer

Dated: August 13, 2002 By: /s/ Steven W. Tholen
--------------------
Steven W. Tholen
Senior Vice President of Finance
and Administration and Chief
Financial Officer

EXHIBIT INDEX