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 Pursuant to Section 13 or 15(d)
[X] of the Securities Exchange Act of 1934
For the Quarterly Period Ended September 30, 2002 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

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

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
incorporation or organization) Identification Number)

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

(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 November 6, 2002, 35,507,418 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 AND COMPREHENSIVE INCOME (LOSS)
(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)

SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
During the nine months ended September 30, 2001, we recorded an allowance for
doubtful accounts related to amounts owed to us by our former chief executive
officer. During the nine months ended September 30, 2002, we received and took
in as treasury stock 600,000 shares of common stock from A. E. Benton as a
result of the finalization of his plan of reorganization. During the nine months
ended September 30, 2002, we reversed 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 other properties (see Note 11).

See accompanying notes to consolidated financial statements.

6

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

NINE MONTHS ENDED SEPTEMBER 30, 2002 (UNAUDITED)

NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The 2001 Annual Report on Form 10-K of Harvest Natural Resources, Inc. includes
certain definitions and a summary of significant accounting policies that should
be read in conjunction with this Quarterly Report on Form 10-Q. The financial
statements for the periods presented herein are unaudited and do not contain all
information required by generally accepted accounting principles to be included
in a full set of financial statements. In the opinion of management, all
material adjustments necessary to present fairly the results of operations have
been included. All such adjustments are of a normal, recurring nature. The
results of operations for any interim period are not necessarily indicative of
the results of operations for the entire year. The consolidated financial
statements include certain reclassifications that were made to conform to
current period presentation.

Investments in entities in which we have a significant ownership interest and
exercise significant control, generally 20 to 50 percent, are accounted for
using the equity method of accounting. We have investments in two entities that
we account for under the equity method, Limited Liability Company "Geoilbent"
("Geoilbent") and Arctic Gas Company ("Arctic Gas"). We sold our entire
ownership interest in Arctic Gas in April 2002.

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 $12.4 million in commercial paper at September 30, 2002.

DERIVATIVES AND HEDGING

We began in the three months ended September 30, 2002 to use a derivative
instrument to manage market risk resulting from fluctuations in the commodity
price of crude oil. Benton-Vinccler, C.A. (See Note 8) entered into a commodity
contract (costless collar), which requires payments to (or receipts from)
counterparties based on a West Texas Intermediate floor price of $23.00 and a
ceiling price of $30.15 for 6,000 barrels of oil per day. The notional amount of
this financial instrument is based on expected production from the drilling of
Tucupita development wells. This instrument protects our projected investment
return by reducing the impact of an unexpected downward crude oil price
movement. The hedge covers expected sales of production for six months beginning
in mid-August 2002. Due to the pricing structure of our Venezuelan oil, this
collar has the economic effect of hedging approximately 12,000 barrels of oil
per day.

In order for a derivative instrument to qualify for hedge accounting, there must
have been clear correlation between the derivative instrument and the forecasted
transaction. Correlation of the commodity contract was determined by evaluating
whether the contract gains and losses would substantially offset the effects of
price changes on the underlying crude oil sales volumes. To the extent that
correlation exists between the contract and the underlying crude oil sales
volumes, realized gains or losses and related cash flows arising from the
contracts are recognized as a component of oil revenue in the same period as the
sale of the underlying volumes.

This derivative contract has been designated as a cash flow hedge. For all
derivatives designated as cash flow hedges, we formally document the
relationship between the derivative contract and the hedged item, as well as the
risk management objective for entering into the contract. To be designated as a
cash flow hedge transaction, the relationship between the derivative and the
hedged item must be highly effective in achieving the offset of changes in cash
flows attributable to the risk both at the inception of the derivative and on an
ongoing basis. We measure the hedge effectiveness on a quarterly basis and hedge
accounting is discontinued prospectively if it is determined that the derivative
is no longer effective in offsetting changes in the cash flows of the hedged
item. A loss of $0.7 million, after tax, is reflected in accumulated other
comprehensive loss for the fair market value of this contract at September 30,
2002. In connection with this instrument we had deposited $2.8 million as of
September 30, 2002 with the counterparty.

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.
Changes in the fair value of

7

derivatives for cash flow hedges are recorded each period in other comprehensive
income. Our derivative is a cash flow hedge transaction in which we hedge the
variability of cash flows related to a forecasted transaction. This derivative
instrument is designated as a cash flow hedge and the changes in the fair value
will be reported in other comprehensive income and will be reclassified to
earnings in the period in which earnings are impacted by the variability of the
cash flows of the hedged item. The ineffective portion (if any) of the cash flow
hedge will be recognized in current period earnings.

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 35.0 million and 34.6 million for the
three and nine months ended September 30, 2002, respectively, and 33.9 million
for each of the three and nine months ended September 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 36.5 million and 35.9 million for the
three and nine months ended September 30, 2002, respectively, and 34.0 million
for each of the three and nine months ended September 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).

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 $2.9 million and $17.9 million at September 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.

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 nine months ended
September 30, 2002 and 2001, was $19.9 million and $15.6 million ($2.58 and
$2.12 per equivalent barrel), respectively. The rate for the nine months ended
September 30, 2002 reflects the addition of 33 million equivalent barrels
related to the natural gas contract signed on September 19, 2002, with Petroleos
de Venezuela, S.A. ("PDVSA"). 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. Depreciation expense was $1.1
million and $3.1 million for the nine months ended September 30, 2002 and 2001,
respectively.

NEW ACCOUNTING PRONOUNCEMENTS

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

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

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities". The standard requires companies to recognize
costs associated with exit or disposal activities when they are incurred rather
than at the date of a commitment to an exit or disposal plan. Examples of costs
covered by the standard include lease termination costs and certain employee
severance costs that are associated with a restructuring, discontinued
operation, plant closing, or other exit or disposal activity. SFAS 146 replaces
Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)". The provisions of this statement
shall be effective for exit or disposal activities initiated after December 31,
2002. The Company will account for exit or disposal activities initiated after
December 31, 1002, in accordance with the provisions of SFAS No. 146.

8

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 interest stock ownership 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. On April 12, 2002, we completed the sale of Arctic Gas and
transferred the Arctic Gas shares ("Arctic Gas Sale") and recognized a gain of
$144.1 million ($93.6 million after tax). Equity in earnings of Geoilbent is
based on a fiscal year ending September 30. Results from Geoilbent are reported
three months in arrears. Arctic Gas equity earnings for the twelve days of April
have been reflected in the three months ended June 30, 2002, as a component of
the gain on sale of investments. No dividends have been paid to us from
Geoilbent.

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

NOTE 3 - LONG-TERM DEBT AND LIQUIDITY

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

At December 31, 2001, we had $108.0 million in 11.625 percent senior unsecured
notes due in May 1, 2003, all of which have been redeemed. In November 1997, we
issued $115.0 million in 9.375 percent senior unsecured notes due November 1,
2007 ("2007 Notes"), of which we repurchased $30.0 million. Interest on the 2007
Notes is due May 1 and November 1 of each year. At September 30, 2002, we were
in compliance with all covenants of the indenture.

9

In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan
commercial bank, for construction of an oil pipeline. The loan is in two parts,
with the first part in an original principal amount of $6.0 million that bears
interest payable monthly based on 90-day London Interbank Borrowing Rate
("LIBOR") plus 5 percent with principal payable quarterly for five years. The
second part, in the 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
September 30, 2002 was 30.25 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 mergers and
sale of assets. The Company has guaranteed the repayment of this loan.

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 September 30, 2002.

NOTE 4 - COMMITMENTS AND CONTINGENCIES

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

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 a wholly owned
subsidiary of WRT Energy Corporation, of certain West Cote Blanche Bay
properties for $15.1 million, constituted a fraudulent conveyance under the
Bankruptcy Code. After a court decision in BOGLA's favor, the claim was settled
in September 2002 for a payment to us of $27,500.

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.

See Note 11 - Related Party Transactions regarding A. E. Benton Reorganization.

10

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 nine months ended September 30, 2002 included a non-recurring foreign
payroll tax adjustment of $0.7 million.

TAXES ON INCOME

At December 31, 2001, we had, for federal income tax purposes, operating loss
carryforwards of approximately $130.0 million expiring in the years 2003 through
2020. It is anticipated that substantially all $130.0 million will be used by
the taxable gain from the Arctic Gas Sale. We will not provide deferred tax
assets on future U.S. operating losses.

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 is derived primarily from the production and sale of
oil. Operations included under the heading "United States and other" include
corporate management, exploration, development 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.

11

NOTE 7 - RUSSIAN OPERATIONS

GEOILBENT
We own a 34 percent interest in Geoilbent, a Russian limited liability company
formed in 1991 that develops, produces and markets crude oil in the West Siberia
region of Russia. Our investment in Geoilbent is accounted for using the equity
method. Results from Geoilbent are reported three months in arrears. Sales
quantities attributable to Geoilbent for the nine months ended June 30, 2002 and
2001 were 5.3 million (3.4 million domestic and 1.9 million export) barrels and
3.8 million (0.4 million domestic and 3.4 million export) barrels, respectively.
Prices for crude oil for the nine months ended June 30, 2002 and 2001 averaged
$12.23 ($7.49 domestic and $20.99 export) and $20.50 ($16.34 domestic and $20.96
export) per barrel, respectively. Depletion expense attributable to Geoilbent
for the nine months ended June 30, 2002 and 2001 was $3.32 and $2.63 per barrel,
respectively. Financial information for Geoilbent follows (in thousands). All
amounts represent 100 percent of Geoilbent.

12

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. At the beginning of the third quarter of
2002, Geoilbent owed EBRD $22.0 million and the parallel debt to IMB had been
repaid in full. The interest rate on the EBRD loan is LIBOR plus 4.75 percent
with principal payments due in varying installments on semiannual payment dates
ending by July 27, 2004. The EBRD loan agreement requires that Geoilbent meet
certain financial ratios, including a minimum current ratio. As of September 30,
2002, Geoilbent was not in compliance with the current ratio requirement, but
has received a waiver from EBRD. By agreement dated September 23, 2002, the loan
agreement with EBRD has been restructured into a revolving credit agreement,
with up to $50.0 million available, including the $22 million already
outstanding. Although the loan agreement has been executed, it will become
effective and available for draw down only after certain conditions are
satisfied. The restructured loan agreement will expire on December 31, 2002, if
the conditions are not satisfied or waived. While no assurances can be given,
the Company believes the conditions to the effectiveness of the loan and draw
down will be satisfied. The interest rate for the restructured loan is six-month
LIBOR plus 4.75 percent, with additional interest up to 3 percent during the
term portion of the loan based upon Geoilbent's net income. Principal payments
are due in six equal semiannual installments beginning January 27, 2004. The
existing and restructured loan agreements grant EBRD a security interest in the
assets of Geoilbent and continue to require that Geoilbent meet certain
financial ratios and covenants, including a minimum current ratio. The loan
agreements also provide 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 "Minley"
("Minley"), the other interest owner in Geoilbent, have pledged their ownership
interests in Geoilbent as security for the existing and restructured debt, and
agreed to support Geoilbent in its obligations under the loan agreements,
including providing technical and managerial personnel and resources to develop
its fields. Under these agreements, the Company and Minley are each jointly and
severally liable to EBRD for any losses, damages, liabilities, costs, expenses
and other amounts suffered or sustained arising out of any breach by the other
of its support obligations. The original proceeds from the loans were used by
Geoilbent to develop the North Gubkinskoye Field and proceeds from the
restructured loan will be used to reduce payables and to develop the South
Tarasovskoye Field.

As of June 30, 2002, the composition of Geoilbent's debt was as follows:

(a) In May 2001, Geoilbent obtained a $3.3 million loan from IMB payable in
six quarterly 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 September 30, 2002, Geoilbent had $0.5 million
outstanding with final payment due in November 2002. The balance of
this loan was $1.1 million at June 30, 2002. The $2.5 million
outstanding to IMB under the parallel reserve based loan agreement
described above was paid in full on July 27, 2002.

(b) 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. In addition, Geoilbent received a
$5.0 million subordinated loan with the same terms from Minley. At
September 30, 2002, Geoilbent had accounts payable outstanding of $16.4
million of which approximately $3.9 million was 90 days or more past
due. The amounts outstanding were primarily to contractors and vendors
for drilling and construction services. Under Russian law, creditors,
to whom payments are 90 days or more past due, can force a company into
involuntary bankruptcy. As a minority interest owner in Geoilbent, we
are working with Geoilbent and Minley to take the necessary steps to
bring Geoilbent's payables current with such creditors and the payables
have been significantly reduced from earlier levels. These steps have
included a reduced capital expenditure budget, subordinated loans from
the Company and Minley, and the restructured EBRD loan. There can be no
assurance that Geoilbent will have the ability to repay the loan made
by the Company when due.

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 a predecessor to the
national oil

13

company, PDVSA. The operating service agreement covers the South Monagas Unit.
Under the terms of the operating service agreement, Benton-Vinccler, C.A., 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. On September 19, 2002,
Benton-Vinccler and PDVSA signed an amendment to the operating services
agreement, providing for the delivery of up to 198 billion cubic feet of natural
gas through July 2012 at a price of $1.03 per thousand cubic feet. The
Venezuelan government maintains full ownership of all hydrocarbons in the
fields. Natural gas sales are expected to commence at a rate of 40 to 50 MMcfpd
in the fourth quarter of 2003 and gradually increase up to 70 MMcfpd in 12 to 18
months.

NOTE 9 - UNITED STATES OPERATIONS

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

We acquired a 100 percent interest in three California State offshore oil and
gas leases ("California Leases") and a parcel of onshore property from Molino
Energy Company, LLC. We impaired all of the capitalized costs associated with
the California Leases of $9.2 million and the joint interest receivable of $3.1
million due from Molino Energy at December 31, 1999. The Company has determined
that it will not pursue further development of the California Leases, and will
plug and abandon the previously drilled exploratory well, and undertake any
required lease and land reclamation. It is believed that these costs will not be
material.

NOTE 10 - CHINA OPERATIONS

In December 1996, we acquired Crestone Energy Corporation, subsequently renamed
Benton Offshore China Company. Its principal asset is a petroleum contract with
China National Offshore Oil Corporation ("CNOOC") for the WAB-21 area. The
WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with
an option for an additional 1.25 million acres under certain circumstances, and
lies within an area which is the subject of a territorial dispute between the
People's Republic of China and Vietnam. Vietnam has executed an agreement on a
portion of the same offshore acreage with another company. The territorial
dispute has lasted for many years, and there has been limited exploration and no
development activity in the area under dispute. As part of our review of company
assets, we conducted a third-party evaluation of the WAB-21 area. Through that
evaluation and our own assessment we recorded a $13.4 million impairment charge
in the second quarter of 2002.

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 Arctic Gas Sale.

On May 11, 2001, Mr. Benton and the Company entered into a settlement and
release agreement under which the consulting agreement was terminated as to
future services and Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the repayment of our loans to him. In March
2002, Mr. Benton filed a plan of reorganization in his bankruptcy case which
incorporated the terms of the settlement agreement. On July 31, 2002, the
bankruptcy court confirmed the plan of reorganization, and the order to become
final August 10, 2002. As of that date, Mr. Benton's indebtedness was about $6.7
million for which we provided a full reserve. On August 14, 2002, we exercised
our rights with respect to 600,000 shares of stock in the Company pledged to
repayment of the loan and took the shares into the Company as treasury stock.
Based on a $3.56 closing price for the stock on that date, the value of the
shares was $2.1 million. Also, in September 2002, we received a payment of about
$1.1 million as a partial distribution from Mr. Benton's debtor-in-possession
account. Finally, under the terms

14

of the settlement agreement, we have retained about $0.1 million from the Arctic
Gas bonus payment to Mr. Benton for a total recovery of $3.3 million. We
continue to accrue interest and provide a reserve on the remaining amount due.
About $960,000 remains in the debtor-in-possession account which Mr. Benton has
withheld to cover expenses and estimated tax liability, for the 600,000 shares
of stock we acquired from Mr. Benton. We are due the balance of this account as
the expenses and tax liabilities are finally determined. We also hold the rights
to direct the exercise of Mr. Benton's stock options.

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

NOTE 12 - SUBSEQUENT EVENT - BENTON-VINCCLER, C.A. GAS PIPELINE LOAN

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

15

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", "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 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, acts of
terrorism, currency and exchange risks, changes in existing or potential
tariffs, duties or quotas and other risks described in our filings with the
Securities and Exchange Commission. 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

We possess significant interests in 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.

On February 27, 2002, we entered into a Sale and Purchase Agreement to sell our
entire 68 percent interest stock ownership 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. On April 12, 2002, we
completed the Arctic Gas Sale and recognized a gain of $144.1 million ($93.6
million after tax). We continue to retain a portion of the proceeds from the
Arctic Gas Sale. Among the options under consideration for use of the proceeds
are funding growth opportunities in Russia and Venezuela, further reductions of
debt, purchasing shares of our stock or other corporate purposes. We may also
consider from time to time using our stock as currency, including through
private placements, to help fund growth opportunities.

Oil production from our South Monagas Unit in Venezuela increased 14 percent
with last year's production at 2.7 million barrels (29,500 bopd) for the three
months ended September 30, 2002. In August, 2002, we reduced our 2002 production
guidance by 10 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. In August, we increased the South
Monagas Unit capital expenditures program by $11.4 million to approximately
$42.5 million.

As the result of the gas sales addendum to the operating services agreement
entered into with PDVSA in September 2002, the Company has added proved natural
gas reserves of 198 Bcf, or 33 million barrels of oil equivalent (MMBoe), to
Benton-Vinccler's proved reserves based on a report from Ryder-Scott, our
independent petroleum engineer. Net to our 80 percent interest, this is an
addition of 158 Bcf, or 26 MMBoe, of proved reserves. An initial capital
investment of approximately $25 million will be required in 2003 to build
approximately a 65 mile pipeline to deliver the natural gas to the PDVSA sales
point, modify the Uracoa Field processing plant and for other infrastructure
needs. On October 1, 2002, Benton-Vinccler and Banco Mercantil, C. A. signed a
loan agreement to provide $15.5 million of financing to fund construction of the
gas pipeline and related facilities. Repayment of the loan is guaranteed by us.
The remaining $9.5 million capital investment is expected to be funded with
internally generated funds. We expect to invest an additional $21 million
starting in 2004 for a natural gas pipeline, infrastructure and drilling in the
Bombal Field to sustain the gas production profile to the end of the contract.
Natural gas sales are expected to commence at a rate of 40 to 50 million cubic
feet per day (MMcfpd) in the fourth quarter of 2003 and gradually increase up to
70 MMcfpd in 12 to 18 months.

Geoilbent's current production (quarter ending June 30, 2002) is approximately
19,300 barrels of oil per day. We believe the wells drilled in the South
Tarasovskoye Field in 2001 significantly increased the value of our Russian
investment and we are

16

continuing to explore ways to improve our returns, including improved reservoir
management, a computer simulation study of the field, improved drilling and
completion practices, and construction of a natural gas processing facility. As
discussed in Note 7 of the "Notes to the Consolidated Financial Statements", in
September 2002 Geoilbent and EBRD signed a restructured loan agreement providing
for a $50 million credit facility, including $22 million of existing debt. When
available, proceeds from this loan will be used for development of the South
Tarasovskoye Field and to reduce Geoilbent's payables. Geoilbent is also
pursuing plans to construct the necessary facilities to develop, process and
market natural gas. Among other factors, Geoilbent's ability to undertake this
project will depend upon obtaining financing and entering into satisfactory
marketing agreements.

At September 30, 2002, Geoilbent had accounts payable outstanding of $16.4
million of which approximately $3.9 million was 90 days or more past due. The
amounts outstanding were primarily to contractors and vendors for drilling and
construction services. Under Russian law, creditors, to whom payments are 90
days or more past due, can force a company into involuntary bankruptcy. As a
minority interest owner in Geoilbent, we are working with Geoilbent and Minley
to take the necessary steps to bring Geoilbent's payables current with such
creditors and the payables have been significantly reduced from earlier levels.
These steps have included a reduced capital expenditure budget, subordinated
loans from the Company and Minley, and the restructured EBRD loan. There can be
no assurance that Geoilbent will have the ability to repay the loan made by the
Company when due.

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 nine months ended September 30,
2002 and 2001 reflect results from Geoilbent and Arctic Gas for the nine months
ended June 30, 2002 and 2001, respectively.

You should read the following discussion of the results of operations for the
three and nine months ended September 30, 2002 and 2001 and the financial
condition as of September 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 SEPTEMBER 30, 2002 AND 2001

Our revenues increased $7.4 million during the three months ended September 30,
2002 compared with 2001 due to increased oil sales revenue in Venezuela as a
result of increased sales quantities and world crude oil prices. Our sales
quantities for the three months ended September 30, 2002 from Venezuela were 2.7
million barrels (29,500 barrels of oil per day) compared with 2.4 million
barrels (25,900 barrels of oil per day) for the three months ended September 30,
2001. The increase in sales quantities of 328,000 barrels was due primarily to
our Tucupita drilling program. Prices for crude oil averaged $14.31 per barrel
(pursuant to terms of an operating service agreement) from Venezuela during the
three months ended September 30, 2002 compared with $13.15 per barrel during the
three months ended September 30, 2001.

Our operating expenses decreased $0.8 million, during the three months ended
September 30, 2002 compared with the three months ended September 30, 2001. This
was primarily due to reduced costs for transportation at the Tucupita field and
workovers at the South Monagas Unit in Venezuela. Operating expenses during the
three months ended September 30, 2002 compared with the same period of 2001 were
$3.26 per barrel and $4.06 per barrel, respectively. Depletion, depreciation and
amortization increased $0.2 million during the three months ended September 30,
2002 compared with 2001 primarily due to increased oil production. The depletion
expense per barrel decreased from $2.82 to $2.13 from the second to third
quarter of 2002. The rate decrease was due to the addition of 33 million barrels
of oil equivalent of gas reserves and related future development costs
associated with the South Monagas Unit gas contract. Depletion expense per
barrel of oil produced from Venezuela during the three months ended September
30, 2002 was $2.13 compared with $2.12 during 2001.

We recognized $1.1 million for the impairment of the Lakeside Prospect in South
Louisiana in the three months ended September 30, 2002. Total general and
administrative expenses decreased $1.5 million during the three months ended
September 30, 2002, compared with 2001. This was primarily due to the
restructuring and moving of the corporate office from California in 2001. A bad
debt recovery of $3.3 million was recorded in the third quarter of 2002 related
to the recovery of the allowance for uncollectible accounts in prior years. See
Note 11 - "Related Party Transactions" for a complete discussion of the
recovery.

Gain on sale of investment increased by $1.0 million as a result of
reclassifying gain from investment income and other on the Arctic Gas Sale for
first and second quarter ($0.5 million for the first 12 days of April) losses.
Investment income and other decreased $0.7 million during the three months ended
September 30, 2002 compared with 2001, as we no longer collect interest

17

on our loan to Arctic Gas and the reclassification to gain on sale of investment
of Arctic Gas's first quarter losses. Interest expense decreased $3.6 million
during the three months ended September 30, 2002 compared with 2001. This was
primarily due to the redemption of the 2003 senior unsecured notes and the
purchase of $20 million of 2007 Notes. Net gain on exchange rates increased $0.4
million for the three months ended September 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 $20.1 million during the three months ended September 30, 2002
compared with income of $3.9 million in 2001. This resulted in increased income
tax expense of $3.1 million. The effective tax rate of 33 percent varies from
the U.S. statutory rate of 35 percent primarily because no tax will be due on
the bad debt recovery. A tax benefit is provided for net operating losses
generated in the U.S. that will be utilized by the Arctic Gas Sale. The
effective tax rate declined from 90 percent to 33 percent for the three months
ended September 30, 2002 with 2001. Taxes were provided in more profitable
Venezuelan operations and no income tax benefits were provided on losses
generated in the U.S. in 2001. The income attributable to the minority interest
increased $1.1 million for the three months ended September 30, 2002 compared
with 2001. This was primarily due to the increased profitability of
Benton-Vinccler.

Equity in net earnings of affiliated companies decreased $1.7 million during the
three months ended September 30, 2002 compared with 2001. This was due to the
lower equity income from Geoilbent ($0.8 million) and Arctic Gas ($0.9 million),
respectively.

NINE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001

Our revenues increased $0.6 million during the nine months ended September 30,
2002 compared with 2001. This was due to increased oil sales volumes in
Venezuela and a decrease in world crude oil prices. Our sales quantities for the
nine months ended September 30, 2002 from Venezuela were 7.7 million barrels
(28,300 barrels of oil per day) compared with 7.4 million barrels (27,000
barrels of oil per day) for the nine months ended September 30, 2001. Normal
volume declines in existing wells were offset by new production under the
Tucupita Field development. Prices for crude oil averaged $12.83 per barrel
(pursuant to terms of an operating service agreement) from Venezuela during the
nine months ended September 30, 2002 compared with $13.39 per barrel during the
nine months ended September 30, 2001.

Our operating expenses decreased $7.5 million during the nine months ended
September 30, 2002 compared with the nine months ended September 30, 2001. This
was primarily due to decreased workover costs and transportation costs of oil
from the Tucupita field. Operating expenses during the nine months ended
September 30, 2002 compared with the same period of 2001 were $3.20 per barrel
and $4.37 per barrel, respectively. Depletion, depreciation and amortization
increased $2.3 million during the nine months ended September 30, 2002 compared
with 2001 primarily due to increased oil production. The depletion expense per
barrel increased from $2.12 to $2.58 for the nine months ended September 30,
2001 compared with the nine months ended September 30, 2002. The rate increase
was due to a normal decline due to production which was partially offset in the
third quarter by the addition of 33 million barrels of oil equivalent of gas
reserves and related future development costs associated with the South Monagas
Unit.

We recognized write-downs of oil and gas properties and impairments of $14.5
million and $0.4 million at September 30, 2002 and 2001, respectively. The $14.5
million impairment is for the China WAB-21 area and an impairment of the
Lakeside Prospect in South Louisiana in the nine months ended September 30,
2002. General and administrative expenses decreased $3.3 million during the nine
months ended September 30, 2002 compared with 2001 due to the restructuring and
moving the corporate office from California in 2001. A bad debt recovery of $3.3
million was recorded in the third quarter of 2002 related to the recovery of the
allowance for uncollectible accounts in prior years. See Note 11 - "Related
Party Transactions" for a complete discussion of the recovery. Taxes other than
on income decreased $1.4 million during the nine months ended September 30, 2002
compared with the nine months ended September 30, 2001 primarily due to one-time
municipal tax rate adjustment at the South Monagas Unit in Venezuela, as well as
a non-recurring foreign payroll tax adjustment.

Investment income and other decreased $0.7 million during the nine months ended
September 30, 2002 compared with 2001, primarily due to lower average interest
rates and we no longer collect interest on our loan to Arctic Gas. Interest
expense decreased $5.0 million during the nine months ended September 30, 2002
compared with 2001. This was primarily due to redemption of the 2003 senior
unsecured notes and the purchase of $20 million of 2007 Notes. Net gain on
exchange rates increased $4.6 million for the nine months ended September 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 and minority interests of $164.9 million during the nine
months ended September 30, 2002 compared with income of $11.5 million in 2001.
This resulted in increased income tax expense of $57.5 million. The effective
tax rate of 41 percent varies from the U.S. statutory rate of 35 percent
primarily because income taxes are paid on profitable operations in foreign
jurisdictions. A tax benefit is provided for net operating losses generated in
the U.S. that are utilized by the Arctic Gas Sale. The effective tax rate
declined from 92 percent to 41 percent for the nine months ended September 30,
2002, with 2001. Taxes were provided on more profitable Venezuelan operations
and no income tax benefit was provided on future losses generated in the U.S. in
2001. The high 2001 effective tax rate relates to the tax provision on our
profitable Venezuelan activities without a tax benefit on losses in

18

our U.S. corporate office. The income attributable to the minority interest
increased $1.6 million for the nine months ended September 30, 2002 compared
with 2001. This was primarily due to the increased profitability of
Benton-Vinccler.

Equity in net earnings of affiliated companies decreased $7.2 million during the
nine months ended September 30, 2002 compared with 2001. This was due to lower
equity income from Geoilbent ($6.2 million) and Arctic Gas ($1.0 million),
respectively.

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 September 30, 2002, our cash and marketable securities
balance was $70.6 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. We currently have significant debt principal obligations payable
in 2007 ($85 million). We may pursue additional open market debt purchases of
the 2007 Notes to further reduce the debt. In April 2002, we purchased $20.0
million (face value) of 2007 Notes for $18.8 million plus accrued interest. A
pretax gain of $0.9 million was recognized on the purchase of these notes.

Share Repurchase Plan. In September 2002, our board of directors authorized a
share repurchase program to repurchase up to 1.0 million shares of the Company's
common stock from time to time in open market transactions. To date, no such
shares have been purchased.

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.
On October 1, 2002, Benton-Vinccler executed a note for $15.5 million to fund
construction of a gas pipeline and related facilities to deliver gas from the
Uracoa field to a PDVSA pipeline. The interest rate for this loan is LIBOR plus
6 percentage points determined quarterly. The term is four years with a one year
grace period and a quarterly amortization of $1.3 million. We do not expect this
action to have a material impact on Benton-Vinccler's operations.

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 September 30, 2002, we had current assets of $122.3 million and current
liabilities of $51.4 million, resulting in working capital of $70.9 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 $71.5 million was primarily due to the Arctic Gas Sale.

Cash Flow from Operating Activities. During the nine months ended September 30,
2002 and 2001, net cash provided by operating activities was approximately $27.1
million and $34.7 million, respectively. Cash flow from operating activities
decreased by $7.6 million during the nine months ended September 30, 2002
compared with 2001. This was primarily due to reductions in accounts payable and
accrued expenses.

19

Cash Flow from Investing Activities. A $189.8 million payment was received on
the Arctic Gas Sale. During the nine months ended September 30, 2002 and 2001,
we had drilling and production related capital expenditures of approximately
$32.9 million and $34.6 million, respectively, related primarily to our
Venezuelan operations.

We expect capital expenditures of approximately $42.5 million for calendar year
2002, the majority 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 be required to make
interest payments of approximately $8 million related to the 2007 Notes during
the next 12 months.

Cash Flow from Financing Activities. We have redeemed $108.0 million senior
unsecured notes due in May 1, 2003, and repurchased $30.0 million of the 2007
Notes and paid $3.6 million related to the Benton-Vinccler bank loan. At
September 30, 2002, we were in compliance with all covenants.

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

During the nine months ended September 30, 2002, net foreign exchange gains
attributable to our Venezuelan operations were $4.9 million and net foreign
exchange gains attributable to our Russian operations were $0.2 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 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. The political environment in the countries in which we operate can
be unpredictable. 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 at least the next 12 months. Our expectation is based
upon cash and marketable securities on hand and our current estimate of
projected price levels, production 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 beyond our six month
commodity hedge, 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 and political
conditions that have historically affected the oil and natural gas business
where we operate. Prices for oil are subject to fluctuations in response to
changes in supply, market uncertainty and a variety of factors beyond our
control.

20

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 below.

OIL PRICES

As an independent oil producer, our revenue, other income and equity earnings
and profitability, reserve values, access to capital and future rate of growth
are substantially dependent upon the prevailing prices of crude oil and
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 production have been volatile and unpredictable, and such volatility is
expected to continue. We currently are utilizing a hedge transaction with
respect to a portion of our oil production to achieve a more predictable cash
flow, establish an acceptable rate of return on our Tucupita drilling program,
as well as to reduce our exposure to price fluctuations. While hedging (using a
costless collar) 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. See Note 1 -
Derivatives and Hedging for a complete discussion of our derivative activity.

INTEREST RATES

Total long-term debt at September 30, 2002 of $89.9 million consisted of
fixed-rate senior unsecured notes maturing in 2007 ($85.3 million) and $4.6
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.

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 Venezuelan oil and gas production.
In April, 2002, there was a failed attempt to remove the President of Venezuela,
Hugo Chavez. Since then, President Chavez named a new president of PDVSA who, in
turn, reinstated certain key PDVSA executives whom President Chavez 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. Civil unrest continues
in Venezuela, contributing to continued uncertainty over the business climate.
However, the importance of PDVSA to Venezuela's future is utmost. PDVSA supplies
50 percent of all government revenues, 33 percent of Gross Domestic Product
("GDP") 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.

RISK MANAGEMENT PROGRAM

We are implementing an integrated (and continuously updated) risk management
program to ascertain an optimum risk management policy. This policy must
understand how net asset value, cash flow and earnings uncertainty affect our
market value and how individual risk relates to the program. The types of risk
that we have initially identified are: political, strategic, operational,
business process, product mix, financial, human resource, tax and
legal/regulatory. We have identified key drivers for each type of risk and are
in the process of measuring exposure to our risk management program and avenues
to balance an appropriate risk/reward mitigation strategy. Examples of risk
mitigation are: modifications to strategy or business objectives, adjustments to
capital structure or employing specific financial instruments.

21

ITEM 4. CONTROLS AND PROCEDURES

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

Our principal executive officer and our principal financial officer have
informed us that, based upon their evaluation as of September 30, 2002, of our
disclosure controls and procedures (as defined in Rule 13a-14(c) and Rule
15d-14(c) under the Exchange Act), they have concluded that those disclosure
controls and procedures are effective.

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

22

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For a description of the WRT litigation, see Note 4 - "Commitments and
Contingencies" and for a description of the A. E. Benton Reorganization, see
Note 11 - "Related Party Transactions".

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

10.4 Addendum No. 2 to Operating Services
Agreement Monagas SUR dated 19th September,
2002

10.5 Bank Loan Agreement between Banco Mercantil,
C.A. and Benton-Vinccler C.A. dated October
1, 2002

10.6 Guaranty issued by Harvest Natural
Resources, Inc. dated September 26, 2002.

10.7 Amending and Restating the Credit Agreement
between Limited Liability Company
"Geoilbent" and European Bank for
Reconstruction and Development dated 23rd
September, 2002

10.8 Amendment Agreement relating to Performance,
Subordination and Share Retention Agreement
dated 30th September, 2002

10.9 Amending and Restating the Agreement for
Pledge of Shares in Limited Liability
Company "Geoilbent" dated 23rd June, 1997

10.10 Employment Agreement dated August 1, 2002
between Harvest Natural Resources, Inc. and
Peter J. Hill

10.11 Employment Agreement dated August 1, 2002
between Harvest Natural Resources, Inc. and
Steven W. Tholen

10.12 Employment Agreement dated July 15, 2002
between Harvest Natural Resources, Inc. and
Kerry R. Brittain

10.13 Employment Agreement dated August 1, 2002
between Harvest Natural Resources, Inc. and
Kurt A. Nelson

(b) Reports on Form 8-K

On September 25, 2002, we filed a report announcing
approval by the Board of Directors by the Company to
purchase up to one million shares of the Company's
common stock in open market transactions and announced
the signing of a gas contract on Form 8-K under

Item 5. Other Events and Regulation FD Disclosure,
and

Item 7. Financial Statements and Exhibits.
Press Releases related to items under Item
5.

23

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: November 8, 2002 By: /s/ Peter J. Hill
---------------------------
Peter J. Hill
President and Chief
Executive Officer

Dated: November 8, 2002 By: /s/ Steven W. Tholen
---------------------------
Steven W. Tholen
Senior Vice President of
Finance and Administration
and Chief Financial Officer

24

I, Peter J. Hill, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 8, 2002
/s/ Peter J. Hill
-------------------------------------
Peter J. Hill
President and Chief Executive Officer

25

I, Steven W. Tholen, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 8, 2002
/s/ Steven W. Tholen
-------------------------------------
Steven W. Tholen
Senior Vice President of Finance and
Administration and Chief Financial
Officer

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 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: November 8, 2002 By: /s/ Peter J. Hill
-------------------------------------
Peter J. Hill
President and Chief Executive Officer

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 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: November 8, 2002 By: /s/ Steven W. Tholen
------------------------------------
Steven W. Tholen
Senior Vice President of Finance and
Administration
and Chief Financial Officer