HARVEST NATURAL RESOURCES INC - 10-Q Quarterly Report

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

FORM 10-Q

(Mark One)

[X] Quarterly Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

For the Quarterly Period Ended June 30, 2003 or

[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

for the transition period from to
--- ---

COMMISSION FILE NO. 1-10762

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HARVEST NATURAL RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)

DELAWARE 77-0196707
(State or Other Jurisdiction of (IRS Employer Identification No.)
Incorporation or Organization)

15835 PARK TEN PLACE DRIVE, SUITE 115
HOUSTON, TEXAS 77084
(Address of Principal Executive Offices) (Zip Code)

(281) 579-6700
(Registrant's Telephone Number, Including Area Code)

Indicate by check mark whether the registrant: (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

Yes X No
--- ---

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).

Yes X No
--- ---

At August 8, 2003, 35,250,731 shares of the Registrant's Common Stock were
outstanding.

HARVEST NATURAL RESOURCES, INC.

FORM 10-Q

TABLE OF CONTENTS

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

See accompanying notes to consolidated financial statements.

3

HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)

See accompanying notes to consolidated financial statements.

4

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

See accompanying notes to consolidated financial statements.

5

SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:

During the six months ended June 30, 2003 and 2002, we recorded an
allowance for doubtful accounts of $0.1 million and $0.2 million, respectively,
related to the interest accrued on the remaining amounts owed to us by our
former Chief Executive Officer.

See accompanying notes to consolidated financial statements.

6

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

THREE AND SIX MONTHS ENDED JUNE 30, 2003 AND 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 consolidated financial position as of
June 30, 2003, and the consolidated results of operations and cash flows for the
three and six month periods ended June 30, 2003 and 2002. The unaudited
consolidated 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, 2002.

The consolidated results of operations for the three and six month
periods ended June 30, 2003 are not necessarily indicative of the results to be
expected for the full year.

ORGANIZATION

Harvest Natural Resources, Inc. is engaged in the exploration,
development, production and management of oil and gas properties. We conduct our
business principally in Venezuela (Benton-Vinccler C.A. or "Benton-Vinccler")
and through our equity investment in a Russian entity.

PRINCIPLES OF CONSOLIDATION

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

USE OF ESTIMATES

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

ACCOUNTS AND NOTES RECEIVABLE

Allowance for doubtful accounts related to employee notes was $3.6
million and $3.5 million at June 30, 2003 and December 31, 2002, respectively.

MINORITY INTERESTS

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

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COMPREHENSIVE INCOME

Statement of Financial Accounting Standards No. 130 ("SFAS 130")
requires that all items 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 reflected
unrealized mark-to-market losses from cash flow hedging activities as other
comprehensive loss during the three and six month periods ended June 30, 2003
and, in accordance with SFAS 130, have presented comprehensive loss in the
unaudited consolidated statement of operations.

DERIVATIVES AND HEDGING

Statement of Financial Accounting Standards No. 133, as amended,
establishes accounting and reporting standards for derivative instruments and
hedging activities. All derivatives are recorded on the balance sheet at fair
value. To the extent that the hedge is determined to be effective, changes in
the fair value of derivatives for qualifying cash flow hedges are recorded each
period in other comprehensive income. Our derivatives are cash flow hedge
transactions in which we hedge the variability of cash flows related to
forecasted transactions. These derivative instruments have been designated as a
cash flow hedge and the changes in the fair value will be reported in other
comprehensive income assuming the highly effective test is met, and have been
reclassified to earnings in the period in which earnings are impacted by the
variability of the cash flows of the hedged item.

Benton-Vinccler hedged a portion of its 2003 oil sales by purchasing a
WTI crude oil "put" to protect its 2003 cash flow. The put is for 10,000 barrels
of oil per day for the period of March 1, 2003 through December 31, 2003. This
put qualified under the highly effective test and the mark-to-market loss at
June 30, 2003 is included in other comprehensive loss. Due to the pricing
structure for our Venezuela oil, the put has the economic effect of hedging
approximately 20,800 barrels of oil per day. The put cost is $2.50 per barrel,
or $7.7 million, and has a strike price of $30.00 per barrel. The notional
amount of each financial instrument is based on expected sales of crude oil
production from existing and future development wells and the related
incremental oil production associated with production from high gas-to-oil ratio
wells after the installation of a gas pipeline. These instruments protect our
projected investment return and cash flow derived from our production by
reducing the impact of a downward crude oil price movement until their
expiration. At June 30, 2003, Accumulated Other Comprehensive Loss consisted of
$0.6 million ($0.4 million net of tax) of unrealized losses on our oil sales
hedge. Oil sales for the six months ended June 30, 2003 includes $0.2 million
loss in settlement on this hedge. The deferred net losses recorded in
Accumulated Other Comprehensive Loss are expected to be reclassified to earnings
during the next twelve months.

ASSET RETIREMENT LIABILITY

Effective January 1, 2003, we adopted Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). As
a result of adopting this statement, Benton-Vinccler recorded under the full
cost method of accounting for oil and gas properties an increase in oil and gas
properties as well as a corresponding liability account in the amount of $4.3
million. This asset retirement obligation is associated with the plugging and
abandonment of certain wells in Venezuela. SFAS 143 requires entities to record
the fair value of a liability for a legal obligation to retire an asset in the
period in which the liability is incurred if a reasonable estimate of fair value
can be made. Historically, we determined that there would be no wells to plug
and abandon before returning the fields to PDVSA. In January 2003, one of our
wells suffered a leak in its casing allowing natural gas to travel to the
surface. The well was plugged and abandoned and a comprehensive study of all
existing wells was undertaken. This study indicated an increased likelihood that
we would have to plug and abandon certain of the wells during the term of the
agreement. No prior provision was undertaken and no cumulative adjustment was
required. We have abandoned ten wells in the first six months of 2003. Changes
in asset retirement obligations during the six months ended June 30, 2003 were
as follows:

Asset retirement obligations as of January 1, 2003.............. $ --
Liabilities recorded during the first quarter.............. 4,237
Liabilities incurred during the second quarter............. (2,050)
Accretion expense.......................................... 51
--------
Asset retirement obligations as of June 30, 2003................ $ 2,238
========

8

The pro forma effect, as if FAS 143 had been adopted in the prior
periods, on net income and earnings per share is not material.

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 35.2 million for the three and six
months ended June 30, 2003, and 34.7 million and 34.4 million for the three and
six months ended June 30, 2002, respectively. Diluted EPS reflects the potential
dilution which would 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 36.8 million and 35.2 million for the three and six months ended
June 30, 2003, respectively, and 36.6 million and 35.8 million for the three and
six months ended June 30, 2002, respectively. In September 2002, our board of
directors authorized the repurchase of up to one million shares of our common
stock. For the six months ended June 30, 2003, we repurchased approximately
80,000 shares for an aggregate price of $0.4 million.

An aggregate of 3.1 million and 2.9 million options and warrants to
purchase common stock were excluded from the earnings per share calculations
because their exercise price exceeded the average share price during the three
and six months ended June 30, 2003, respectively, and 4.1 million for the three
and six months ended June 30, 2002, respectively.

STOCK-BASED COMPENSATION

At June 30, 2003, we had several stock-based employee compensation
plans, which are more fully described in Note 6 - Stock Option and Stock
Purchase Plans in our Annual Report on Form 10-K for the year ended December 31,
2002. Prior to 2003, we accounted for those plans under the recognition and
measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to
Employees, and related interpretations. Effective January 1, 2003, we adopted
the fair value recognition provisions of Statement of Financial Accounting
Standards Statement No. 123 ("FAS 123"), Accounting for Stock-Based
Compensation, prospectively to all employee awards granted, modified, or settled
after January 1, 2003. Awards under our plans vest in periodic installments
after one year of their grant and expire ten years from grant date. Therefore,
the costs related to stock-based employee compensation included in the
determination of net income in the three and six months ended June 30, 2003 and
2002 are less than that which would have been recognized if the fair value based
method had been applied to all awards since the original effective date of FAS
123. The following table illustrates the effect on net income and earnings per
share if the fair value based method had been applied to all outstanding and
unvested awards in each period.

9

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. For the six months ended
June 30, 2002 we capitalized interest of $0.3 million. Only overhead that is
directly identified with acquisition, exploration or development activities is
capitalized. No overhead has been capitalized in the six months ended June 30,
2003 and 2002. 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 cost
center were $2.9 million at June 30, 2003 and December 31, 2002. At least
annually we evaluate our unproved properties on a country-by-country basis for
possible impairment. If we abandon all exploration efforts in a country where no
proved reserves are assigned, all exploration and acquisition costs associated
with the country are expensed. Due to the unpredictable nature of exploration
drilling activities, the amount and timing of impairment expenses are difficult
to predict with any certainty. The ultimate timing of when the costs related to
the acquisition of Benton Offshore China Company will be included in amortizable
costs is uncertain.

Statement of Financial Accounting Standards No. 141 - Business
Combinations ("FAS 141") and No. 142 - Goodwill and Other Intangible Assets
("FAS 142") included new terminology on the disclosure of what constitutes an
intangible asset. The Financial Accounting Standards Board ("FASB") and the
Securities and Exchange Commission ("SEC") continue to discuss the appropriate
application of FAS 141 and FAS 142 to a mineral interest associated with proved
and undeveloped oil and gas leasehold acquisition costs, and if those costs
should be separately disclosed and not included in Oil and Gas Properties on the
Consolidated Balance Sheet. We believe that the presentation and disclosure of
the $2.9 million excluded costs attributed to the China cost center is
appropriate pending a final resolution of this issue by the FASB and SEC.

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, substantially all of
which was attributable to the Venezuelan cost center for the six months ended
June 30, 2003 and 2002, was $8.5 million and $14.1 million ($2.54 and $2.82 per
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 $0.7
million in each of the six month periods ended June 30, 2003 and 2002.

NOTE 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES

Our 34 percent equity investment in Geoilbent is 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
company for shares of stock and other costs incurred associated with the
acquisition and evaluation of technical data for the oil fields operated by the
investee company. Equity in earnings of Geoilbent is based on a fiscal year
ending September 30. No dividends have been paid to us from Geoilbent.

10

Equity in earnings and losses and investments in and advances to
Geoilbent are as follows (in thousands):

NOTE 3 - LONG-TERM DEBT

LONG-TERM DEBT

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

In November 1997, we issued $115.0 million in 9.375 percent senior
unsecured notes due November 1, 2007 ("2007 Notes"), of which we have
repurchased $30.0 million. Interest on the 2007 Notes is due May 1 and November
1 of each year.

In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan
commercial bank, for construction of an oil pipeline. The unpaid portion of the
loan bears interest payable monthly based on 90-day London Interbank Borrowing
Rate ("LIBOR") plus 5 percent with principal payable quarterly for five years.

On October 1, 2002, Benton-Vinccler executed a note and borrowed $15.5
million to fund construction of a gas pipeline and related facilities to deliver
natural gas from the Uracoa Field to a Petroleos de Venezuela, S.A. ("PDVSA")
pipeline. The interest rate for this loan is LIBOR plus 6 percentage points
determined quarterly. The term is four years with a quarterly amortization of
$1.3 million beginning with the first quarter 2004 to coincide with the first
payment from our gas sales.

The notes payable ($18.8 million) provide for certain limitations on
mergers and sale of assets. The Company has guaranteed the repayment of these
notes.

At June 30, 2003, we and Benton-Vinccler were in compliance with all
note covenants.

NOTE 4 - COMMITMENTS AND CONTINGENCIES

We have employment contracts with four executive officers which provide
for annual base salaries, eligibility for bonus compensation and various
benefits. The contracts provide for a lump sum payment as a multiple of base
salary in the event of termination of employment without cause. In addition,
these contracts provide for payments as a multiple of base salary and bonus, tax
reimbursement and a continuation of benefits in the event of termination without

11

cause following a change in control of the Company. By providing one year
notice, these agreements may be terminated by either party on May 31, 2004.

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

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. The six months ended June
30, 2002 included a non-recurring foreign payroll adjustment of $0.7 million. We
have incurred the following Venezuelan municipal taxes and other taxes (in
thousands):

TAXES ON INCOME

At December 31, 2002, we had, for U.S. federal income tax purposes,
operating loss carryforwards of approximately $52.1 million expiring in the
years 2018 through 2022. Income tax expense represents foreign income taxes
attributable to our Venezuela operations.

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

NOTE 6 - OPERATING SEGMENTS

We regularly allocate resources to and assess the performance of our
operations by segments that are organized by unique geographic and operating
characteristics. The segments are organized in order to manage regional
business, currency and tax related risks and opportunities. Revenues from the
Venezuela operating segment are derived 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:

NOTE 7 - RUSSIAN OPERATIONS

GEOILBENT

We own 34 percent of Geoilbent, a Russian limited liability company,
formed in 1991 to develop, produce and market crude oil from the North
Gubkinskoye and South Tarasovskoye Fields in the West Siberia region of Russia.
Our investment in Geoilbent is accounted for using the equity method. Sales
quantities attributable to Geoilbent for the six months ended March 31, 2003 and
2002 were 2.9 million barrels (1.8 million domestic and 1.1 million export) and
3.5 million barrels (2.3 million domestic and 1.2 million export), respectively.
Prices for crude oil for the six months ended March 31, 2003 and 2002 averaged
$13.73 ($7.69 domestic and $23.48 export) and $11.17 ($6.83 domestic and $19.62
export) per barrel, respectively. Depletion expense attributable to Geoilbent
for the six months ended March 31, 2003 and 2002 was $3.74 and $3.44 per barrel,
respectively. All amounts represent 100 percent of Geoilbent. Summarized
financial information for Geoilbent follows (in thousands):

Due to low Russian domestic oil prices, the net present value of
Geoilbent's proved reserves at December 31, 2002 was lower than Geoilbent's
unamortized capitalized cost of its oil and gas properties at that date. As a
result, Geoilbent recorded a $50 million full cost ceiling test write-down in
the three months ended December 31, 2002. Russian domestic oil prices
historically decline in the winter months due to export limitations and rise in
the spring and early summer. However, during the period Russian domestic prices
have remained low and a further full cost ceiling write-down was not required
for the quarter ending March 31, 2003.

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. The IMB portion was
repaid in November 2002. By agreement dated September 23, 2002, the loan
agreement with EBRD was restructured into a revolving credit agreement, with up
to $50 million available, including $22 million already outstanding as of
December 31, 2002. The interest rate for the restructured loan is six-month
LIBOR plus 4.75 percent, increasing up to an additional 3 percent during the
term portion of the loan based upon Geoilbent's net income. Principal payments
are due in six equal semiannual installments beginning January 27, 2004. The
outstanding loan balance at March 31, 2003 was $30.0 million. The restructured
loan agreement grants EBRD a security interest in the assets of Geoilbent and
requires that Geoilbent meet certain financial ratios and covenants, including a
minimum current ratio. The loan agreement also provides for certain limitations
on liens, additional indebtedness, certain investments, capital expenditures,
dividends, mergers and sales of assets. In addition, the Company and Open Joint
Stock Company Minlay ("Minlay"), have pledged their ownership interests in
Geoilbent as security for the debt, and agreed to support Geoilbent in its
obligations under the loan agreement, including providing technical and
managerial personnel and resources to develop its fields. Under these
agreements, the Company and Minlay are each jointly and severally liable to EBRD
for any losses, damages, liabilities, costs, expenses and other amounts suffered
or sustained arising out of any breach by the other of its support obligations.

The loan agreement requires that Geoilbent implement a new management
information system by May 1, 2003. Geoilbent was unable to satisfy this
requirement which results in a potential event of default whereby EBRD may, at
its option, demand payment by Geoilbent of the outstanding principal and
interest and sell all or part of our ownership interest in Geoilbent to satisfy
the debt. In addition, Geoilbent must meet a current ratio requirement of 1.1:1
beginning with the fourth quarter of 2002. If Geoilbent fails to meet the ratio
requirements for two consecutive quarters it will also result in a potential
event of default whereby EBRD may, at its option, demand payment by Geoilbent of
the outstanding principal and interest and sell all or part of our ownership
interest in Geoilbent to satisfy the debt. Geoilbent failed to meet the ratio
requirements for the quarters ended March 31, 2003 and December 31, 2002.
Geoilbent has not received a notice of event of default from EBRD. At March 31,
2003 and September 30, 2002, the current liabilities of Geoilbent exceeded its
current assets by $41.3 million and $35.3 million, respectively. Included in
current liabilities at March 31, 2003 is the $30.0 million EBRD loan. This debt
was classified as current because Geoilbent could not implement the new
management information system by May 1, 2003. As a result of this situation,
Geoilbent's independent accountants indicated in their September 30, 2002 audit
report that substantial doubt exists regarding Geoilbent's ability to meet its
debts as they come due. While no assurance can be given, we believe these
covenant defaults are temporary and do not result in an other than temporary
decline in the value of our investment in Geoilbent.

Because of Geoilbent's significant working capital deficit, a
substantial portion of its cash flow must be utilized to reduce accounts and
taxes payable. Geoilbent's net cash provided by operating activities is
dependent on the level of production and oil prices. Oil prices in Russia have
been historically volatile and are significantly impacted by the proportion of
production that Geoilbent can sell on the export market. Historically, Geoilbent
has supplemented its cash flow from operations with additional borrowings or
equity capital and may need to continue to do so. Should oil prices decline for
a prolonged period or should Geoilbent not have access to additional capital,
Geoilbent would need to reduce its capital expenditures, which could limit its
ability to maintain or increase

14

production and, in turn, meet its debt service requirements. Asset sales and
financing are restricted under the terms of the EBRD loan.

Geoilbent management plans to further address the working capital
deficit by reducing certain capital expenditures and funding its 2003 debt
service and planned capital expenditures with cash flows from existing producing
properties and its development drilling program. At March 31, 2003, Geoilbent
had accounts payable outstanding of $11.5 million of which approximately $2.3
million was 90 days or more past due. The amounts outstanding were primarily to
contractors and vendors for drilling and construction services. On March 12,
2003, Geoilbent borrowed $8.0 million under the EBRD loan to reduce payables.
Under Russian law, creditors to whom payments are 90 days or more past due can
force a company into involuntary bankruptcy. Geoilbent's financial statements do
not include any adjustments which might result if Geoilbent were unable to
continue as a going concern.

As of September 30, 2002, the Geoilbent shareholders had provided
Geoilbent with subordinated loans totaling $7.5 million ($2.5 million from the
Company and $5.0 million from Minlay). These loans are unsecured, repayable in
January 2004 and are recorded as a current liability at March 31, 2003. The
interest rate is based on LIBOR up to January 2004, and rises to 8 to 12 percent
thereafter. There can be no assurance that Geoilbent will have the ability to
repay the loans made by the Company and Minlay when due.

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. The export tariff as of June 30, 2003 was approximately $3.67 per barrel.
When Urals crude is below $15 per barrel no tariff is collected. Effective
January 1, 2002, the 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, 2003, the base rate for the
unified natural resources production tax is set at $1.55 per barrel of crude oil
produced and is to be adjusted on the market price of Urals blend and the
Russian Ruble/US Dollar exchange rate. From January 1, 2004 to December 31,
2006, the production tax will increase from $1.55 per barrel to $1.58 per barrel
of crude oil produced. The tax rate is zero if the Urals blend price falls to or
below $8.00 per barrel. From January 1, 2007, the unified natural resources
production tax rate is set by law at 16.5 percent of crude oil revenues.

Geoilbent currently employs two expatriates and approximately 700 local
employees.

A South Tarasovskoye well was drilled during the first half of 2003 and
completed in June 2003, with an initial production rate of 650 barrels of oil
per day with no significant water. A second South Tarasovskoye well was drilling
as of June 30, 2003. Subsequently, the well reached total depth and is now being
completed in the Jurassic formation. A full assessment of the reserves
discovered has yet to be prepared. A well on the Vansko-Namisky prospect was
drilled to a depth of approximately 4,400 feet, cased and further operations
suspended due to low Russian domestic oil prices.

ARCTIC GAS COMPANY

On April 12, 2002, we sold our 68 percent equity interest in Arctic
Gas. The equity earnings of Arctic Gas have historically been based on a fiscal
year ended September 30. The Statements of Operations shown below are reflected
in our results for the three and six months ended March 31, 2002.

We accounted for our interest in Arctic Gas using the equity method due
to the significant influence we exercised over the operating and financial
policies of Arctic Gas. Our weighted-average equity interest, for the three and
six months ended March 31, 2002 was 68 and 40 percent, respectively. Summarized
financial information for Arctic Gas follows (in thousands). All amounts
represent 100 percent of Arctic Gas.

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NOTE 8 - VENEZUELA OPERATIONS

Two of the three planned wells in the Bombal Field were drilled in the
six months ended June 30, 2003.

NOTE 9 - UNITED STATES OPERATIONS

In 1998, we acquired a 100 percent interest in three California State
offshore oil and gas leases ("California Leases") and a parcel of onshore
property from Molino Energy Company, LLC. We impaired all of the capitalized
costs associated with the California Leases and the onshore property. The
California Leases have expired, and the previously drilled exploratory well was
plugged and abandoned in July 2003. We will undertake any required lease and
land reclamation, which we believe will not be material, and sell the onshore
property.

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

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. A discussion of these factors is included in our 2002 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.

AVAILABLE INFORMATION

We file annual, quarterly, 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 principal accounting officer. The text
of the code of ethics has been posted on the Governance section of the Company's
website.

CAPITAL RESOURCES AND LIQUIDITY

Debt Reduction. We currently have a significant debt principal
obligation payable in 2007 ($85 million). We intend to continue to evaluate open
market debt purchases of the obligations due in 2007 to further reduce debt.

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

17

At June 30, 2003, we had current assets of $122.3 million and current
liabilities of $50.7 million, resulting in working capital of $71.6 million and
a current ratio of 2.4:1. This compares with a working capital of $97.0 million
and a current ratio of 3.8:1 at December 31, 2002. The decrease in working
capital of $25.4 million was primarily due to the lack of Venezuelan crude sales
during part of the first quarter of 2003 and the purchase of our WTI crude oil
"put" for $7.7 million.

Cash Flow from Operating Activities. During the six months ended June
30, 2003 and 2002, net cash provided by operating activities was approximately
$22.4 million and $11.9 million, respectively. Approximately $18.9 million of
the increase was due to changes in operating assets and liabilities. The
increase in operating assets and liabilities was primarily due to accruals of
costs related to Benton-Vinccler workovers and the gas sales project offset by a
decrease in income taxes payable.

Cash Flow from Investing Activities. During the six months ended June
30, 2003 and 2002, we had drilling and production-related capital expenditures
of approximately $35.5 million and $20.7 million, respectively. Included in the
$35.5 million is the cost of drilling two wells in the Bombal Field and the
addition of $4.3 million for the asset retirement liability. See Note 1 -
Organization and Summary of Significant Accounting Policies. Although the first
well drilled in the Bombal Field initially produced approximately 2,500 barrels
of oil per day, current production has fallen to around 500 barrels of oil per
day due to water encroachment. We soon will be implementing a gas lift plan in
the field designed to improve oil production. Benton-Vinccler is progressing on
its gas project. Our capital expenditure guidance has been increased by $9
million to reflect in part the decision to purchase instead of lease the
compression and dehydration units. The four phases to the project are: 1) Gas
delivery pipeline, 2) UM-2 plant facilities, 3) Gas compression and dehydration
units at the UM-2 plant, and 4) Metering and receiving facilities at PDVSA's
Mamo station. These projects are on schedule with first gas sales projected from
the Uracoa Field in the fourth quarter of 2003. The ability to sell gas will
eliminate the current gas handling volume restriction at the UM-2 processing
plant and enable us to drill future oil wells into an area just below the gas
cap. The six months ended June 30, 2002 included a $189.8 million payment on the
sale of Arctic Gas.

RESULTS OF OPERATIONS

You should read the following discussion of the results of operations
for the three and six months ended June 30, 2003 and 2002 and the financial
condition as of June 30, 2003 and December 31, 2002 in conjunction with our
consolidated financial statements and related notes included in our Annual
Report on Form 10-K for the year ended December 31, 2002.

THREE MONTHS ENDED JUNE 30, 2003 AND 2002

Our results of operations for the three months ended June 30, 2003
primarily reflected the results for Benton-Vinccler, which accounted for all of
our production and oil sales revenue. Oil revenue per barrel increased 1 percent
(from $13.37 in 2002 to $13.53 in 2003) and oil sales quantities decreased 16
percent (from 2.5 million barrels "MMBbls" of oil in 2002 to 2.1 MMBbls of oil
in 2003) during the three months ended June 30, 2003 compared with 2002.

Our revenues decreased $4.4 million, or 13 percent, during the three
months ended June 30, 2003 compared with 2002. This was due to lower production
offset by higher world crude oil prices. Our sales quantities for the three
months ended June 30, 2003 from Venezuela were 23,200 barrels of oil per day
"BOPD" compared with 27,100 BOPD for the three months ended 2002. Volumes were
lower due to natural reservoir decline rates and the fact that some wells did
not immediately return to previous production levels following the national work
stoppage. In addition, expected production from the Bombal Field to help offset
these declines has been delayed until a gas lift plan is implemented.

Our operating expenses increased $1.0 million, or 12 percent, during
the three months ended June 30, 2003 compared with the three months ended 2002.
This was primarily due to increased workover activity in an effort to return
wells to previous production levels following the national work stoppage.
Depletion, depreciation and amortization decreased $1.6 million, or 22 percent,
during the three months ended June 30, 2003 compared with the three months ended
2002 due to decreased production at the South Monagas Unit and the addition of
natural gas reserves in the third quarter 2002. Depletion expense per barrel of
oil produced from Venezuela during the three months ended June 30, 2003 was
$2.53 compared with $2.37 during the three months ended 2002. We recognized

18

write-downs of $13.4 million at June 30, 2002 for the impairment of the China
WAB-21 block as well as capitalized costs associated with exploration prospects.
General and administrative expenses decreased $1.6 million, or 30 percent,
during the three months ended June 30, 2003 compared with the three months ended
2002. This was, in part, due to severance payments paid in the second quarter of
2002. Taxes other than on income decreased during the three months ended June
30, 2003 compared with the three months ended 2002. This was primarily due to
decreased Venezuelan municipal taxes, which are a function of oil revenues.

Interest expense decreased $1.9 million, or 41 percent, during the
three months ended June 30, 2003 compared with the three months ended 2002. This
was primarily due to the redemption of $108 million of 2003 notes on May 1,
2002, repurchase of $20 million 2007 notes, the repayment of the Venezuelan
Bolivar denominated debt and normal debt service. Net gain on exchange rates
decreased $2.4 million for the three months ended June 30, 2003 compared with
the three months ended 2002. This was due to Bolivar currency controls imposed
in February 2003 which fixed the exchange rate between the Bolivar and the U.S.
dollar and restricts the ability to exchange Bolivars for dollars and vice
versa. We realized income before income taxes and minority interest of $6.4
million during the three months ended June 30, 2003 compared with income of
$140.2 million in the three months ended 2002. Income before income taxes and
minority interest for the three months ended June 30, 2002 included a $143.1
million gain on the sale of Arctic Gas. Income tax expense declined $56.6
million due to the lower pre-tax income. The effective tax rate increased from
43 to 49 percent in the three months ended June 30, 2003 compared to 2002. The
increase was due to foreign income taxes incurred on profitable foreign
operations and an increase in U.S. losses for which no tax benefit is recorded.
The income attributable to the minority interest decreased $0.8 million for the
three months ended June 30, 2003 compared with the three months ended 2002. This
decrease was due to the decreased production of Benton-Vinccler.

Equity in net losses of affiliated companies decreased $1.3 million
during the three months ended June 30, 2003 compared with the three months ended
2002. See Note 7 - Russian Operations. The three months ended June 30, 2002
included a loss of $0.7 million on Arctic Gas.

SIX MONTHS ENDED JUNE 30, 2003 AND 2002

Our revenues decreased $12.9 million, or 21 percent, during the six
months ended June 30, 2003 compared with 2002. This was primarily due to lower
production offset by higher world crude oil prices. Our sales quantities for the
six months ended June 30, 2003 from Venezuela were 18,400 BOPD compared with
27,700 BOPD for the six months ended 2002. Volumes were lower due to the
national work stoppage, natural reservoir decline rates and the fact that some
wells did not immediately return to previous production levels following the
national work stoppage. In addition, expected production from the Bombal Field
to help offset these declines has been delayed until a gas lift plan is
implemented.

Our operating expense remained flat during the six months ended June
30, 2003 compared with the six months ended 2002. This was primarily due to
lower production volumes offset by higher workover and maintenance expenses.
Depletion, depreciation and amortization decreased $5.5 million, or 38 percent,
during the six months ended June 30, 2003 compared with the six months ended
2002 due to decreased production and the addition of natural gas reserves in the
third quarter 2002. Depletion expense per barrel of oil produced from Venezuela
during the six months ended June 30, 2003 was $2.54 compared with $2.37 during
the six months ended 2002. We recognized write-downs of $13.4 million at June
30, 2002 for the impairment of the China WAB-21 block as well as capitalized
costs associated with exploration prospects. General and administrative expenses
decreased $1.6 million, or 19 percent, during the six months ended June 30, 2003
compared with the six months ended 2002. This was, in part, due to severance
payments paid in the second quarter 2002. Taxes other than on income decreased
during the six months ended June 30, 2003 compared with the six months ended
2002. This was primarily due to decreased Venezuelan municipal taxes, which are
a function of oil revenues.

Interest expense decreased $5.7 million, or 52 percent, during the six
months ended June 30, 2003 compared with the six months ended 2002. This was
primarily due to the redemption and repurchase of debt. Net gain on exchange
rates decreased $3.9 million for the six months ended June 30, 2003 compared
with the six months ended 2002. This was due to Bolivar currency controls
imposed in February 2003 which fixed the exchange rate between the Bolivar and
the U.S. dollar and restricts the ability to exchange Bolivars for dollars and
vice versa. We realized income before income taxes and minority interest of $9.4
million during the six months ended June 30, 2003 compared with income of $144.8
million in the six months ended 2002. Income before income taxes and minority

19

interest for the six moths ended June 30, 2002 included a $143.1 million gain on
the sale of Arctic Gas. Income tax expense decreased $57.3 million due to lower
pre-tax income. The effective tax rate increased from 42 to 44 percent in the
six months ended June 30, 2003 compared with 2002. The increase was due to
foreign income taxes incurred on profitable foreign operations and an increase
in U.S. losses for which no benefit is recorded. The income attributable to the
minority interest decreased $1.3 million for the six months ended June 30, 2003
compared with the six months ended 2002. This decrease was due to the decreased
production of Benton-Vinccler.

Equity in net losses of affiliated companies decreased $15.3 million
during the six months ended June 30, 2003 compared with the six months ended
2002. Equity in net losses included a $17.0 million (our share) full cost
ceiling test write-down. See Note 7 - Russian Operations. The six months ended
June 30, 2002 included a loss of $1.0 million on Arctic Gas.

EFFECTS OF FOREIGN EXCHANGE RATES

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. In February 2003,
Bolivar currency controls were imposed which fixed the exchange rate between the
Bolivar and the U.S. dollar and restricts the ability to exchange Bolivars for
dollars and vice versa. Oil companies, such as Benton-Vinccler, are allowed to
receive payments for oil sales in U.S. currency and pay dollar-denominated
expenses from those payments. We are unable to predict the full impact of the
currency controls on us or Benton-Vinccler. At present, the Russian Ruble is not
a convertible currency outside the Russian Federation. Future movements in the
exchange rates between the Russian Ruble and the US dollar will affect the
carrying value of Geoilbent's Russian Ruble denominated assets and liabilities
and our ability to realize non-monetary assets represented in US dollars in
Geoilbent's financial statements.

CONCLUSION

While we can give you no assurance, we believe that our cash flow from
operations and $76.8 million cash will provide sufficient capital resources and
liquidity to fund our planned capital expenditures, investments in and advances
to Geoilbent and semiannual interest payment obligations for the next 12 months.
Our expectation is based upon our current estimate of projected price levels,
including our current hedge program, ability to remit funds from Benton-Vinccler
and an assumption that there will be no material interruption in production or
delays in the time periods between the submission of quarterly invoices to PDVSA
by Benton-Vinccler and the subsequent payments of these invoices by PDVSA.
Future cash flows are subject to a number of variables including, but not
limited to, the level of production, prices, as well as various economic and
political 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.

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, foreign exchange and political risk, as discussed in
our Annual Report on Form 10-K for the year ended December 31, 2002.

ITEM 4. CONTROLS AND PROCEDURES

In its recent Release No. 33-8238, effective August 14, 2003, the SEC,
among other things, adopted rules requiring reporting companies to maintain
disclosure controls and procedures to provide reasonable assurance that a
registrant is able to record, process, summarize and report the information
required in the registrant's quarterly and annual reports under the Securities
Exchange Act of 1934 (the "Exchange Act"). While we believe that our existing
disclosure controls and procedures have been effective to accomplish these
objectives, we intend to continue to examine, refine and formalize our
disclosure controls and procedures and to monitor ongoing developments in this
area.

20

Our principal executive officer and our principal financial officer
have informed us that, based upon their evaluation, as of June 30, 2003, of our
disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule
15d-15(e) under the Exchange Act), they have concluded that those disclosure
controls and procedures are effective and there were no significant changes in
internal controls or factors that could significantly alter their evaluation.

21

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now
known as Harvest Natural Resources, Inc., Chemex, Inc., Benton
Vinccler, C.A., Gale Campbell and Sheila Campbell in the
District Court for Harris County, Texas. This suit was brought
in May, 2003 by Excel alleging, inter alia, breach of a
consulting agreement between Excel and Harvest,
misappropriation of proprietary information and trade secrets,
and fraud. Excel seeks actual and exemplary damages,
injunctive relief and attorneys' fees. Harvest disputes
Excel's claims and will vigorously defend against them.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

See Note 7 - Russian Operations contained in Item 1 of Part 1
of this quarterly report on Form 10-Q with respect to a
discussion of a potential loan default by Geoilbent which
discussion is incorporated by reference into this Item 3.

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

At our Annual Meeting of Shareholders held on May 22, 2003,
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, 2003:

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

31.1 Certifications accompanying Quarterly Report pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002
executed by Peter J. Hill, President and Chief
Executive Officer and Steven W. Tholen, Senior Vice
President, Chief Financial Officer and Treasurer.

32.1 Certifications accompanying Quarterly Report pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
executed by Peter J. Hill, President and Chief
Executive Officer and Steven W. Tholen, Senior Vice
President, Chief Financial Officer and Treasurer.

(b) Reports on Form 8-K

On May 8, 2003, we filed a Report on Form 8-K for a press
release dated May 7, 2003 announcing our first quarter 2003
results.

22

SIGNATURES

Pursuant to the requirements of 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 12, 2003 By: /s/ Peter J. Hill
-------------------------------------
Peter J. Hill
President and Chief Executive Officer

Dated: August 12, 2003 By: /s/ Steven W. Tholen
-------------------------------------
Steven W. Tholen
Senior Vice President,
Chief Financial Officer and Treasurer

23

EXHIBIT INDEX