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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 March 31, 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
_____________________________________
HARVEST NATURAL RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 77-0196707
(State or Other Jurisdiction of Incorporation (IRS Employer Identification No.)
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 May 5, 2003, 35,216,211 shares of the Registrant's Common Stock were
outstanding.
HARVEST NATURAL RESOURCES, INC.
FORM 10-Q
TABLE OF CONTENTS
Page
----
PART I FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Unaudited Consolidated Balance Sheets at March 31, 2003
and December 31, 2002.......................................................... 3
Unaudited Consolidated Statements of Operations and
Comprehensive Income for the Three Months
Ended March 31, 2003 and 2002.................................................. 4
Unaudited Consolidated Statements of Cash Flows for the Three
Months Ended March 31, 2003 and 2002........................................... 5
Notes to Consolidated Financial Statements.......................................... 7
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................................................... 18
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK...................................................................... 23
Item 4. CONTROLS AND PROCEDURES................................................................ 24
PART II OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS...................................................................... 25
Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.............................................. 25
Item 3. DEFAULTS UPON SENIOR SECURITIES........................................................ 25
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................................... 25
Item 5. OTHER INFORMATION...................................................................... 25
Item 6. EXHIBITS AND REPORTS ON FORM 8-K....................................................... 25
SIGNATURES............................................................................................ 26
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
MARCH 31, DECEMBER 31,
2003 2002
------------- -------------
(in thousands)
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents............................................. $ 61,763 $ 64,501
Restricted cash....................................................... 12 1,812
Marketable securities................................................. 27,070 27,388
Accounts and notes receivable:
Accrued oil sales................................................. 19,908 27,359
Joint interest and other, net..................................... 9,505 8,002
Commodity hedging contract............................................ 10,835 --
Prepaid expenses and other............................................ 2,591 2,969
------------- -------------
TOTAL CURRENT ASSETS......................................... 131,684 132,031
RESTRICTED CASH............................................................ 16 16
OTHER ASSETS ............................................................. 2,358 2,520
DEFERRED INCOME TAXES...................................................... 3,403 4,082
INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANY.......................... 35,705 51,783
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of $2,900
excluded from amortization in 2003 and 2002, respectively)........ 589,075 576,601
Furniture and fixtures................................................ 7,520 7,503
------------- -------------
596,595 584,104
Accumulated depletion, depreciation and amortization.................. (442,845) (439,344)
------------- -------------
153,750 144,760
------------- -------------
$ 326,916 $ 335,192
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other..................................... $ 6,139 $ 3,804
Accrued expenses...................................................... 20,251 20,644
Accrued interest payable.............................................. 3,637 1,405
Income taxes payable.................................................. 5,565 6,880
Commodity hedging contract............................................ -- 430
Current portion of long-term debt..................................... 2,192 1,867
------------- -------------
TOTAL CURRENT LIABILITIES 37,784 35,030
LONG-TERM DEBT............................................................. 101,608 104,700
ASSET RETIREMENT LIABILITY................................................. 4,263 --
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST.......................................................... 25,031 24,145
STOCKHOLDERS' EQUITY:
Preferred stock, par value $0.01 a share; authorized 5,000 shares;
outstanding, none................................................. -- --
Common stock, par value $0.01 a share; authorized 80,000 shares;
issued 35,947 shares at March 31, 2003 and 35,900 shares at
December 31, 2002................................................ 359 359
Additional paid-in capital............................................ 173,721 173,559
Retained (deficit).................................................... (15,225) 234
Accumulated other comprehensive income................................ 2,614 --
Treasury stock, at cost, 730 shares and 650 shares at March 31, 2003
and December 31, 2002, respectively.............................. (3,239) (2,835)
------------- -------------
TOTAL STOCKHOLDERS' EQUITY................................... 158,230 171,317
------------- -------------
$ 326,916 $ 335,192
============= =============
See accompanying notes to consolidated financial statements.
3
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
THREE MONTHS ENDED MARCH 31,
------------------------------------
2003 2002
------------- -------------
(in thousands, except per share data)
REVENUES
Oil sales............................................................. $ 19,390 $ 27,247
Ineffective hedge activity............................................ (565) --
------------- -------------
18,825 27,247
EXPENSES
Operating expenses.................................................... 6,515 7,418
Depletion, depreciation and amortization.............................. 3,515 7,440
General and administrative............................................ 3,224 3,278
Taxes other than on income............................................ 647 584
------------- -------------
13,901 18,720
------------- -------------
INCOME FROM OPERATIONS..................................................... 4,924 8,527
OTHER NON-OPERATING INCOME (EXPENSE)
Investment earnings and other......................................... 278 506
Interest expense...................................................... (2,668) (6,509)
Net gain on exchange rates............................................ 526 2,055
------------- -------------
(1,864) (3,948)
------------- --------------
INCOME FROM CONSOLIDATED COMPANIES BEFORE
INCOME TAXES AND MINORITY INTERESTS................................... 3,060 4,579
INCOME TAX EXPENSE......................................................... 1,056 1,801
------------- -------------
INCOME BEFORE MINORITY INTERESTS........................................... 2,004 2,778
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY COMPANIES..................... 887 1,380
------------- -------------
INCOME FROM CONSOLIDATED COMPANIES......................................... 1,117 1,398
EQUITY IN NET EARNINGS (LOSS) OF AFFILIATED COMPANIES...................... (16,575) 87
-------------- -------------
NET INCOME (LOSS).......................................................... $ (15,458) $ 1,485
============== =============
OTHER COMPREHENSIVE INCOME: UNREALIZED MARK TO MARKET
GAIN FROM CASH FLOW HEDGING ACTIVITIES, NET OF TAX ................... 2,614 --
------------- -------------
$ (12,844) $ 1,485
============= =============
NET INCOME LOSS PER COMMON SHARE:
Basic ............................................................. $ (0.44) $ 0.04
============= =============
Diluted ............................................................. $ (0.44) $ 0.04
============= =============
See accompanying notes to consolidated financial statements.
4
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
THREE MONTHS ENDED MARCH 31,
------------------------------
2003 2002
------------- -------------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)..................................................... $ (15,458) $ 1,485
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation and amortization.......................... 3,515 7,440
Amortization of financing costs................................... 140 300
Loss on disposition of assets..................................... -- 77
Equity in earnings of affiliated companies........................ 16,575 (87)
Allowance for employee notes and accounts receivable.............. 51 81
Non-cash compensation-related charges............................. 42 --
Minority interest in undistributed earnings of subsidiaries....... 887 1,380
Deferred income taxes............................................. (667) (1,697)
Changes in Operating Assets and Liabilities:
Accounts and notes receivable..................................... 5,896 (3,173)
Prepaid expenses and other........................................ 378 (2,545)
Commodity hedging contract........................................ (6,875) --
Accounts payable.................................................. 2,335 4,585
Accrued expenses.................................................. (393) (1,373)
Accrued interest payable.......................................... 2,231 (655)
Asset retirement liability........................................ 4,263 --
Commodity hedging contract payable................................ (430) --
Income taxes payable.............................................. (1,315) 2,700
------------- -------------
NET CASH PROVIDED BY OPERATING ACTIVITIES.................... 11,175 8,518
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Partial payment on sale of equity interest............................ -- 120,900
Additions of property and equipment................................... (12,505) (12,721)
Investment in and advances to affiliated companies.................... (497) (10,625)
Decrease in restricted cash........................................... 1,800 --
Purchases of marketable securities.................................... (200,332) --
Maturities of marketable securities................................... 200,650 --
------------- -------------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES.......... (10,884) 97,554
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from exercise of stock options........................... 120 471
Purchase of treasury stock............................................ (404) --
Payments of notes payable............................................. (2,767) (109,724)
Decrease in other assets.............................................. 22 16
------------- -------------
NET CASH USED IN FINANCING ACTIVITIES........................ (3,029) (109,237)
------------- -------------
NET DECREASE IN CASH AND CASH EQUIVALENTS.................... (2,738) (3,165)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD........................... 64,501 9,024
------------- -------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD................................. $ 61,763 $ 5,859
============= =============
SUPPLEMENTAL DISCLOSURES OR CASH FLOW INFORMATION
Cash paid during the period for interest.............................. $ 2,071 $ 7,496
============= =============
Cash paid during the period for income taxes.......................... $ 864 $ 935
============= =============
See accompanying notes to consolidated financial statements.
5
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the three months ended March 31, 2003 and 2002, we recorded an allowance
for doubtful accounts related to the interest accrued on the remaining amounts
owed to us by our former Chief Executive Officer (see Note 11 - Related Party
Transactions).
See accompanying notes to consolidated financial statements.
6
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THREE MONTHS ENDED MARCH 31, 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 financial position as of March 31,
2003, and the results of operations and cash flows for the three month periods
ended March 31, 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 results of operations for the three month period ended March 31, 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 March 31, 2003 and December 31, 2002, respectively (see Note
11 - Related Party Transactions).
MINORITY INTERESTS
We record a minority interest attributable to the minority shareholder of
our Venezuela subsidiaries. The minority interest in net income and losses is
subtracted or added to arrive at consolidated net income.
7
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 gains from cash flow hedging activities as other
comprehensive income during the three month period ended March 31, 2003 and, in
accordance with SFAS 130, have provided a separate line 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.
We began in the third quarter of 2002 to use a derivative instrument to
manage market risk resulting from fluctuations in the commodity price of crude
oil. Benton-Vinccler (see Note 8 - Venezuela Operations) entered into a
commodity contract (costless collar), which required payments to (or receipts
from) counterparties based on a West Texas Intermediate ("WTI") crude oil floor
price of $23.00 and a ceiling price of $30.15 for 6,000 barrels of oil per day.
The costless collar was to cover expected sales of production for six months
beginning in mid-August 2002. In December 2002, we determined it was probable
that the remaining underlying crude oil would not be delivered under the
costless collar due to the Venezuelan civil work stoppage and the cessation of
production. Accordingly, hedge accounting was discontinued on the costless
collar and the value of the derivative was recorded as a revenue reduction in
the amount of $0.8 million, $0.6 million of which was recorded in the three
months ended March 31, 2003. Venezuelan production resumed on February 8, 2003.
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 gain at March
31, 2003 is included in other comprehensive income. 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 shut-in high gas-to-oil ratio wells from the
installation of the gas pipeline. These instruments protect our projected
investment return and cash flow by reducing the impact of a downward crude oil
price movement.
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 this statement, the Venezuelan cost center under the full cost
method of accounting as well as a corresponding liability account were both
increased by $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. A legal obligation is a liability that a
party is required to settle as a result of an existing or enacted law, statute,
ordinance or written or oral contract or by legal construction of a contract
under the doctrine of promissory estoppel. When the liability is initially
recorded, the entity should capitalize a cost by increasing the carrying amount
of the related long-lived asset. Over time, the liability is adjusted to its
present value by recognizing accretion expense as an operating expense in the
income statement each period, and the capitalized cost is included under the
full cost method of accounting for oil and gas properties. Amounts recorded
under SFAS 143 are subject to various assumptions and determinations, such as
determining whether a legal obligation exists to remove assets, estimating the
fair value of the costs of removal, estimating when final removal will occur,
and the credit-adjusted risk-free interest rate to be utilized on discounting
future liabilities. Changes that may arise over time with regard to these
assumptions and determinations will change amounts recorded in the future as
expense for asset retirement obligations. We operate under an operating service
agreement to reactivate and develop three Venezuelan oil fields (See Note 8 -
Venezuela Operations). Under the terms of this
8
agreement, all wells are returned to PDVSA at the expiration of the agreement,
but PDVSA has the right to require us to plug and abandon wells that are
abandoned before the expiration of the agreement. 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
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. If we abandon any well or asset at the end
of its useful life, without a legal obligation to do so, we will record
abandonment costs at that time by including those costs in the appropriate cost
center. Changes in asset retirement obligations during the three months ended
March 31, 2003 were as follows:
Asset retirement obligations as of January 1, 2003... $ --
Liabilities recorded during the first quarter.... 4,263
Accretion expense................................ --
------
Asset retirement obligations as of March 31, 2003.... $4,263
======
The pro forma effect, as if FAS 143 had been adopted in the prior periods,
on net income and earnings per share was 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 35.3 million and 34.1 million for the
three months ended March 31, 2003 and 2002, respectively. Diluted EPS reflects
the potential dilution that 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 36.9 million and 34.7 million for the three months
ended March 31, 2003 and 2002, respectively. In September 2002, our board of
directors authorized the repurchase of up to one million shares of our common
stock. For the three months ended March 31, 2003, we repurchased approximately
80,000 shares for an aggregate price of $0.4 million.
An aggregate of 3.0 million and 4.9 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
months ended March 31, 2003 and 2002, respectively.
STOCK-BASED COMPENSATION
At March 31, 2003, we have 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 FASB 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 cost related to stock-based employee compensation
included in the determination of net income in the three months ended March 31,
2002 is 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
THREE MONTHS ENDED MARCH 31,
2003 2002
----------- -----------
(in thousands)
Net income (loss), as reported....................... $ (15,458) $ 1,485
Add: Stock based employee compensation cost,
net of tax...................................... 42 --
Less: Total stock-based employee compensation
cost determined under fair value based
method, net of tax.............................. (243) (529)
---------- ------------
Net income (loss) - proforma......................... $ (15,659) $ 956
========== ===========
Earnings per share:
Basic - as reported......................... $ (0.44) $ 0.04
========== ===========
Basic - proforma............................ $ (0.44) $ 0.03
========== ===========
Diluted - as reported....................... $ (0.44) $ 0.04
========== ===========
Diluted - proforma.......................... $ (0.44) $ 0.03
========== ===========
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 three months ended
March 31, 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 three months ended March
31, 2002 and 2003. 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 March 31, 2003 and December 31, 2002. We regularly evaluate
our unproved properties on a country-by-country basis for possible impairment.
If we abandon all exploration efforts in a country where no proved reserves are
assigned, all exploration and acquisition costs associated with the country are
expensed. Due to the unpredictable nature of exploration drilling activities,
the amount and timing of impairment expenses are difficult to predict with any
certainty. The ultimate timing of when the costs related to the acquisition of
Benton Offshore China Company will be included in amortizable costs is
uncertain.
All capitalized costs and estimated future development costs (including
estimated dismantlement, restoration and abandonment costs) of proved reserves
are depleted using the units of production method based on the total proved
reserves of the country cost center. Depletion expense, substantially all of
which was attributable to the Venezuelan cost center for the three months ended
March 31, 2003 and 2002, was $3.2 million and $7.3 million ($2.57 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 $0.4
million, and $0.1 million for the three months ended March 31, 2003 and 2002,
respectively.
NOTE 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES
The 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 companies for shares of stock
and other costs incurred associated with the acquisition and evaluation of
technical data for the oil and natural gas fields operated by the investee
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):
MARCH 31, DECEMBER 31,
2003 2002
------------- -------------
Investments
Equity in net assets.................................................. $ 28,056 $ 28,056
Other costs, net of amortization...................................... 747 263
------------- -------------
Total investments................................................. 28,803 28,319
Advances .................................................................. 2,540 2,527
Equity in earnings......................................................... 4,362 20,937
------------- -------------
Total................................................................. $ 35,705 $ 51,783
============= =============
NOTE 3 - LONG-TERM DEBT
LONG-TERM DEBT
Long-term debt consists of the following (in thousands):
MARCH 31, DECEMBER 31,
2003 2002
------------- -------------
Senior unsecured notes with interest at 9.375%.
See description below................................................. $ 85,000 $ 85,000
Note payable with interest at 6.4%.
See description below................................................. 3,300 3,900
Bolivar denominated note payable.
See description below................................................. - 2,167
Note payable with interest at 7.4%.
See description below................................................. 15,500 15,500
------------- -------------
103,800 106,567
Less current portion....................................................... 2,192 1,867
------------- -------------
$ 101,608 $ 104,700
============= =============
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 loan is in two parts,
with the first part in an original principal amount of $6.0 million which 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 original principal amount of 4.4 billion Venezuelan Bolivars
("Bolivars"), 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 Bolivar denominated loan was repaid on March 31, 2003.
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 remaining notes payable ($18.8 million) provide for certain limitations
on mergers and sale of assets. The Company has guaranteed the repayment of these
notes.
11
Loans related to Benton-Vinccler's oil and gas pipeline project loans allow
the lender to accelerate repayment if production ceases for a period greater
than thirty days. During December 2002, when production in Venezuela was
interrupted, Benton-Vinccler was granted a waiver of this provision until
February 18, 2003 in exchange for a prepayment of the next two principal
obligations aggregating $0.9 million. This prepayment, while using cash
reserves, reduced our net interest expense as the current interest expense was
more than the current interest income earned on the invested funds. On February
8, 2003, Benton-Vinccler recommenced production, thereby eliminating the need
for an additional waiver.
At March 31, 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 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 that we no longer occupy under a lease agreement that
expires in December 2004, all of which has been subleased for rents that
approximate our lease costs.
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 three months ended March 31,
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):
THREE MONTHS ENDED MARCH 31,
2003 2002
------------- -------------
Venezuelan Municipal Taxes................................................. $ 513 $ 933
Franchise Taxes............................................................ 27 33
Payroll and Other Taxes.................................................... 107 (382)
------------- -------------
$ 647 $ 584
============= =============
TAXES ON INCOME
At December 31, 2002, we had, for U.S. federal income tax purposes,
operating loss carryforwards of approximately $56.3 million expiring in the
years 2011 through 2022. Income tax expense represents foreign 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
12
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:
THREE MONTHS ENDED MARCH 31,
2003 2002
------------- -------------
(in thousands)
OPERATING SEGMENT REVENUES
Oil Sales:
Venezuela............................................................. $ 18,825 $ 27,247
------------- -------------
Total oil sales................................................... 18,825 27,247
------------- -------------
OPERATING SEGMENT INCOME
Venezuela............................................................. 3,538 5,506
Russia ............................................................. (16,158) (398)
United States and other............................................... (2,837) (3,623)
-------------- -------------
Net income (loss)................................................. $ (15,457) $ 1,485
============== =============
MARCH 31, DECEMBER 31,
2003 2002
------------- -------------
OPERATING SEGMENT ASSETS
Venezuela............................................................. $ 220,573 $ 209,733
Russia ............................................................. 36,284 52,302
United States and other............................................... 121,285 122,355
------------- -------------
Subtotal ............................................................. 378,142 384,390
Intersegment eliminations............................................. (51,226) (49,198)
-------------- -------------
$ 326,916 $ 335,192
============= =============
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 three months ended December 31, 2002 and 2001
were 1.5 million barrels (1.0 million domestic and 0.5 million export) and 1.9
million barrels (1.2 million domestic and 0.7 million export), respectively.
Prices for crude oil for the three months ended December 31, 2002 and 2001
averaged $14.65 ($10.09 domestic and $22.79 export) and $13.36 ($8.92 domestic
and $21.43 export) per barrel, respectively. Depletion expense attributable to
Geoilbent for the three months ended December 31, 2002 and 2001 was $3.32 and
$2.44 per barrel, respectively. All amounts represent 100 percent of Geoilbent.
Summarized financial information for Geoilbent follows (in thousands):
13
STATEMENTS OF INCOME: THREE MONTHS ENDED DECEMBER 31,
2002 2001
------------- -------------
Revenues
Oil sales............................................................. $ 21,921 $ 25,608
Expenses
Selling and distribution expenses..................................... 1,046 2,277
Operating expenses.................................................... 4,356 3,850
Impairment of oil and gas properties.................................. 50,000 --
Depletion, depreciation and amortization.............................. 5,691 6,360
General and administrative............................................ 1,545 2,522
Taxes other than on income............................................ 7,963 7,006
------------- -------------
70,601 22,015
------------- -------------
Income (loss) from operations.............................................. (49,680) 3,593
Other Non-Operating Income (Expense)
Other income.......................................................... (574) 566
Interest expense...................................................... (479) (1,689)
Net gain on exchange rates............................................ 113 664
------------- -------------
(940) (459)
------------- -------------
Income (loss) before income taxes.......................................... (49,620) 3,134
Income tax expense (benefit)............................................... (870) 1,993
------------- -------------
Net income (loss).......................................................... $ (48,750) $ 1,141
============= =============
BALANCE SHEET DATA: DECEMBER 31, 2002 SEPTEMBER 30, 2002
----------------- ------------------
Current Assets ........................................... $ 20,829 $ 18,785
Other Assets ............................................. 133,894 186,815
Current Liabilities ...................................... 53,743 54,051
Other Liabilities ........................................ 7,500 7,500
Net Equity................................................ 83,480 144,049
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 impairment 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 further full cost ceiling impairments may occur depending
on the Russian domestic oil price.
The European Bank for Reconstruction and Development ("EBRD") and
International Moscow Bank ("IMB") together agreed in 1996 to lend up to $65
million to Geoilbent, based on achieving certain reserve and production
milestones, under parallel reserve-based loan agreements. As of December 31,
2002, the outstanding balance of the loan with EBRD was $22 million. 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 the $22 million already outstanding.
The interest rate for the restructured loan is six-month LIBOR plus 4.75
percent, with additional interest up to 3 percent during the term portion of the
loan based upon Geoilbent's net income. Principal payments are due in six equal
semiannual installments beginning January 27, 2004. The 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
14
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. As available, proceeds from the
restructured loan will be used to reduce payables and to develop the South
Tarasovskoye Field.
The restructured loan agreement required that Geoilbent implement a new
management 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 principle and interest and sell all or part of our ownership
interest in Geoilbent to satisfy the debt. At December 31, 2002, and September
30, 2002, the current liabilities of Geoilbent exceeded its current assets by
$32.9 and $35.3 million, respectively. Included in current liabilities as of
December 31, 2002 is the $22.0 million EBRD loan. This debt was classified as
current because Geoilbent could not implement the new management information
system by May 1, 2003 as required by the EBRD facility. As a result of this
situation, Geoilbent's independent accountants have indicated in their September
30, 2002 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 oil prices, which are historically volatile and are significantly impacted by
the proportion of production that Geoilbent can sell on the export market.
Historically, Geoilbent has supplemented its cash flow from operations with
additional borrowings or equity capital and may need to continue to do so.
Should oil prices decline for a prolonged period or should Geoilbent not have
access to additional capital, Geoilbent would need to reduce its capital
expenditures, which could limit its ability to maintain or increase production
and, in turn, meet its debt service requirements. Asset sales and financing are
restricted under the terms of the EBRD loan.
Geoilbent management plans to further address the working capital deficit
by reducing certain capital expenditures and funding its 2003 debt service and
planned capital expenditures with cash flows from existing producing properties
and its development drilling program. At December 31, 2002, Geoilbent had
accounts payable outstanding of $12.2 million of which approximately $5.9
million was 90 days or more past due. The amounts outstanding were primarily to
contractors and vendors for drilling and construction services. 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 that 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 Harvest and
$5.0 million from Minlay). These loans are unsecured and repayable in January
2004. The interest rate is based on LIBOR up to January 2004, and rises from 8
to 12 percent thereafter. There can be no assurance that Geoilbent will have the
ability to repay the loans made by the Company when due.
ARCTIC GAS COMPANY
On April 12, 2002, we sold Arctic Gas and transferred our 68 percent equity
interest to the buyer. 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 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
15
three months ended December 31, 2001 was 40 percent. Summarized financial
information for Arctic Gas follows (in thousands). All amounts represent 100
percent of Arctic Gas.
THREE MONTHS ENDED
STATEMENTS OF OPERATIONS: DECEMBER 31, 2001
------------------
Oil sales.................................................................. $ 3,945
Expenses
Selling and distribution expenses..................................... 1,565
Operating expenses.................................................... 898
Depreciation ......................................................... 251
General and administrative............................................ 1,072
Taxes other than on income............................................ 547
-------------
4,333
-------------
Loss from operations....................................................... (388)
Other Non-Operating Income (Expense)
Other expenses........................................................ (5)
Interest expense...................................................... (335)
Net loss on exchange rates............................................ (33)
-------------
(373)
-------------
Loss before income taxes................................................... (761)
Income tax benefit......................................................... --
-------------
Net loss................................................................... $ (761)
=============
BALANCE SHEET DATA:
DECEMBER 31, 2001
------------------
Current assets ................................................... $ 3,340
Other assets ..................................................... 13,817
Current liabilities .............................................. 33,758
Net deficit....................................................... (16,601)
NOTE 8 - VENEZUELA OPERATIONS
On July 31, 1992, we and our partner, Venezolana de Inversiones y
Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement
to reactivate and further develop three Venezuelan oil fields with Lagoven,
S.A., then one of three exploration and production affiliates of the national
oil company, PDVSA. The operating service agreement covers the Uracoa, Bombal
and Tucupita Fields that comprise the South Monagas Unit. Under the terms of the
operating service agreement, Benton-Vinccler, a Venezuelan corporation owned 80
percent by us and 20 percent by Vinccler, is a contractor for PDVSA and is
responsible for overall operations of the South Monagas Unit, including all
necessary investments to reactivate and develop the fields comprising the South
Monagas Unit. Benton-Vinccler receives an operating fee in U.S. dollars
deposited into a U.S. commercial bank account for each barrel of crude oil
produced (subject to periodic adjustments to reflect changes in a special energy
index of the U.S. Consumer Price Index) and is reimbursed according to a
prescribed formula in U.S. dollars for its capital costs, provided that such
operating fee and cost recovery fee cannot exceed the maximum dollar amount per
barrel set forth in the agreement.
On September 19, 2002, Benton-Vinccler and PDVSA signed an amendment to the
operating service agreement, providing for the delivery of up to 198 Bcf of
natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales are
expected to commence at a rate of 40 to 50 MMcf of natural gas per day in the
fourth quarter of 2003 and gradually increase up to 70 MMcfpd in 12 to 18 months
from the initial sale. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5
million barrels of oil at $7.00 per barrel beginning with its first gas sale.
16
Initial gas production will come from the Uracoa field, which allows us to more
efficiently manage the reservoir and eliminate the restrictions on producing oil
wells with high gas to oil ratios. The gas reserves in the Bombal field will be
used to meet the future terms of the gas contract in 2005 or 2006.
The Venezuelan government maintains full ownership of all hydrocarbons in
the fields.
No wells were drilled in the three months ended March 31, 2003.
NOTE 9 - UNITED STATES OPERATIONS
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 we will plug and abandon a 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 for the WAB-21 area. The
WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with
an option for an additional 1.25 million acres under certain circumstances, and
lies within an area which is the subject of a territorial dispute between the
People's Republic of China and Vietnam. Vietnam has executed an agreement on a
portion of the same offshore acreage with another company. The territorial
dispute has lasted for many years, and there has been limited exploration and no
development activity in the area under dispute. As part of our review of company
assets, we conducted a third-party evaluation of the WAB-21 area. Through that
evaluation and our own assessment we recorded a $13.4 million impairment charge
in the second quarter of 2002. WAB-21 represents the $2.9 million excluded from
the full cost pool as reflected on our March 31, 2003 and December 31, 2002
balance sheets.
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 which we recorded as a reduction
of the gain on the Arctic Gas Sale.
On May 11, 2001, Mr. Benton and the Company entered into a settlement and
release agreement under which the consulting agreement was terminated as to
future services and Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the repayment of our loans to him. On July 31,
2002, the bankruptcy court confirmed the plan of reorganization, which
incorporated the terms of the settlement. As of that date, Mr. Benton's
indebtedness was about $6.7 million for which we provided a full reserve. Under
the settlement agreement and plan of reorganization we have recovered $3.3
million of Mr. Benton's obligation. We continue to accrue interest and provide a
reserve on the remaining amount due.
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 sale of our interest in
Arctic Gas. Mr. Benton and the Company have agreed to submit their dispute to
binding arbitration. While the outcome of arbitration cannot be predicted, we
believe that we have a substantial basis for our positions and intend to
vigorously pursue them.
17
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, and current reports, proxy statements, and other
documents with the SEC under the Securities Act of 1934. The public may read and
copy any materials that we file with the SEC at the SEC's Public Reference Room
at 450 Fifth Street, NW, Washington, DC 20549. The public may obtain information
on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. Also, the SEC maintains an Internet website that contains
reports, proxy and information statements, and other information regarding
issuers, including the Company, that file electronically with the SEC. The
public can obtain any documents that we file with SEC at http://www.sec.gov.
We also make available, free of charge on or through our Internet website
(http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on
Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those
reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon
as reasonably practicable after we electronically file such material with, or
furnish it to, the SEC. In addition, the Company has adopted a code of ethics
that applies to all of its employees, including its chief executive officer,
principal financial officer and principle accounting officer. The text of the
code of ethics has been posted on the Governance section of the Company's
website.
MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS
We had two overriding strategic priorities for 2002: (i) to reduce the
amount of debt on the balance sheet; and (ii) to improve the value of our
producing assets. We also strengthened our management team and recommitted, as a
management team and board of directors, to maintain the highest standards in
corporate governance, financial transparency and business ethics.
The balance sheet was significantly strengthened by completing the sale of
Arctic Gas which produced $220 million in cash and net proceeds, after taxes and
expenses, of $190 million (including $30 million for repayment of our
intercompany debt) that were used, in part, to redeem all of the $108 million of
11.625 percent senior notes due in May 2003 ("2003 Notes"). An additional $20
million of the $105 million of 9.375 percent senior notes due in November 2007
were also retired. The balance of the proceeds were retained to improve our
financial flexibility and to be available for acquisitions, reduction of debt or
other general corporate purposes. This strategy of strengthening our balance
sheet has already been partially rewarded by our ability to maintain our
financial flexibility in spite of the temporary loss of production as a result
of the national civil work stoppage in
18
Venezuela. At March 31, 2003, we had $88.8 million of cash or marketable
securities and a long debt-to-total capital ratio of 37 percent.
CAPITAL RESOURCES AND LIQUIDITY
The oil and natural gas industry is a highly capital intensive and cyclical
business with unique operating and financial risks (see Risk Factors in our
Annual Report on Form 10-K for the year ended December 31, 2002). We require
capital principally to service our debt and to fund the following costs:
o drilling and completion costs of wells and the cost of production,
treating and transportation facilities;
o geological, geophysical and seismic costs; and
o acquisition of interests in oil and gas properties.
The amount of available capital will affect the scope of our operations and
the rate of our growth. Our future rate of growth also depends substantially
upon the prevailing prices of oil. Prices also affect the amount of cash flow
available for capital expenditures and our ability to service our debt.
Benton-Vinccler has hedged a portion of its 2003 oil sales by purchasing a WTI
crude oil "put" to protect its 2003 cash flow. The put is for 10,000 barrels of
oil per day for the period of March 1, 2003 through December 31, 2003. Due to
the pricing structure for our Venezuela oil, the put has the economic effect of
hedging approximately 20,800 Bopd. The put cost is $2.50 per barrel, or
approximately $7.7 million, and has a strike price of $30.00 per barrel.
On February 5, 2003, the Venezuelan government imposed currency controls
and created the Commission for Administration of Foreign Currency ("CADIVI")
with the task of establishing the detailed rules and regulations and generally
administering the exchange control regime. The currency controls fix the
exchange rate between the Bolivar and the U.S. dollar, and restricts the ability
to exchange Bolivars for dollars and vice versa. Oil companies, such as
Benton-Vinccler are allowed to receive payments for oil sales in U.S. currency
and pay dollar-denominated expenses from those payments. The near-term effect of
the currency restriction has been to restrict Benton-Vinccler's ability to make
payments to employees and vendors in Bolivars, causing it to borrow money on a
short-term basis to meet these obligations. All of these short-term borrowings
have been repaid and while we now have Bolivars to meet our current obligations,
the situation could change. In addition, the currency controls increased the
cost of Benton-Vinccler's Bolivar denominated debt. Benton-Vinccler repaid the
entire Bolivar denominated debt on March 31, 2003. We are unable to predict the
full impact of the currency controls on us or Benton-Vinccler as the CADIVI has
not issued final regulations.
In the future, our ability to pay interest on our debt and general
corporate overhead can be dependent upon the ability of Benton-Vinccler to make
loan repayments, dividends and other cash payments to us. However, there have
been, and may again be, unforeseeable interruptions in oil and gas sales or
there may be contractual obligations or legal impediments such as the recently
instituted currency controls to receiving dividends or distributions from
Benton-Vinccler, which could prohibit Benton-Vinccler from remitting funds to
us. Management does not believe that the currency controls will prohibit our
ability to receive funds from Benton-Vinccler, although were it to do so, our
ability to meet our cash requirements would be adversely affected.
Debt Reduction. We currently have a significant debt principal obligation
payable in 2007 ($85 million). We intend to continue to evaluate open market
debt purchases of the obligations due in 2007 to further reduce debt. On March
31, 2003, Benton-Vinccler repaid all $2.2 million of its outstanding Bolivar
denominated debt.
Working Capital. Our capital resources and liquidity are affected by the timing
of our semiannual interest payments of approximately $4.0 million each May 1 and
November 1 on the 2007 Notes and by receipt of the quarterly payments from PDVSA
at the end of the months of February, May, August and November pursuant to the
terms of the contract between Benton-Vinccler and PDVSA regarding the South
Monagas Unit. As a consequence of the timing of these interest payment outflows
and the PDVSA payment inflows, our cash balances can increase and decrease
dramatically on a few dates during the year. In each May and November in
particular, interest payments at the beginning of the month and PDVSA payments
at the end of the month create large swings in our cash balances.
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:
19
THREE MONTHS ENDED MARCH 31,
-------------------------------------------
2003 2002
----------- ---------------
(in thousands)
Net cash provided by operating activities............ $ 11,175 $ 8,518
Net cash provided by (used in) investing activities.. (10,884) 97,554
Net cash provided by (used in) financing activities.. (3,029) (109,237)
----------- ---------------
Net increase (decrease) in cash...................... $ (2,738) $ (3,165)
=========== ===============
At March 31, 2003, we had current assets of $131.7 million and current
liabilities of $37.8 million, resulting in working capital of $93.9 million and
a current ratio of 3.5:1. 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 $3.1 million was primarily due to the lack of Venezuelan crude sales
during the civil national work stoppage.
Cash Flow from Operating Activities. During the three months ended March
31, 2003 and 2002, net cash provided by operating activities was approximately
$11.2 million and $8.5 million, respectively. The $2.7 million increase was
primarily due to changes in operating assets and liabilities.
Cash Flow from Investing Activities. During the three months ended March
31, 2003 and 2002, we had drilling and production-related capital expenditures
of approximately $12.5 million and $12.7 million, respectively. Included in the
$12.5 million was the addition of $4.3 million for the asset retirement
liability. See Note 1 - Organization and Summary of Significant Accounting
Policies. The three months ended March 31, 2002 included $120.9 million partial
payment on sale of Arctic Gas.
The timing and size of capital expenditures for the South Monagas Unit are
entirely at our discretion. We anticipate that Geoilbent will continue to fund
its expenditures through its own cash flow and credit facilities. Our remaining
capital commitments worldwide are relatively minimal and are substantially at
our discretion. We will also be required to make annual interest payments of
approximately $8.0 million on the 2007 Notes.
Cash Flow from Financing Activities. During the three months ended March
31, 2003, Benton-Vinccler repaid all of its Bolivar Denominated debt ($1.9
million) and $0.9 million of its US dollar debt. $0.6 million of the US dollar
debt was an acceleration of the next two principle payments discussed in Note 3
- - Long-Term Debt and Liquidity.
We have an approximately $11,000 lease obligation per month for our Houston
office space. This lease is valid through August 2004. The following table
summarizes our contractual obligations at March 31, 2003.
PAYMENTS (IN THOUSANDS) DUE BY PERIOD
-------------------------------------------------------------------------
LESS THAN AFTER 4
CONTRACTUAL OBLIGATION TOTAL 1 YEAR 1-2 YEARS 3-4 YEARS YEARS
---------------------- ----------- ----------- --------- --------- -----------
Long Term Debt $ 103,800 $ 2,192 $ 6,367 $ 6,367 $ 88,874
Building Lease 220 132 88 -- --
----------- ----------- ----------- ----------- -----------
Total $ 104,020 $ 2,324 $ 6,455 $ 6,367 $ 88,874
=========== =========== =========== =========== ===========
We currently have a significant debt obligation of $85 million payable in
November 2007. Our ability to meet our debt obligation and to reduce our level
of debt depends on the successful implementation of our strategic objectives.
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 three months ended March 31, 2003
and 2002 reflect results from Geoilbent and Arctic Gas (which was sold on April
12, 2002) for the three months ended December 31, 2002 and 2001, respectively.
We follow the full-cost method of accounting for our investments in oil and
gas properties. We capitalize
20
all acquisition, exploration, and development costs incurred. We account for our
oil and gas properties using cost centers on a country-by-country basis. We
credit proceeds from sales of oil and gas properties to the full-cost pools if
the sales do not result in a significant change in the relationship between
costs and the value of proved reserves or the underlying value of unproved
property. We amortize capitalized costs of oil and gas properties within the
cost centers on an overall unit-of-production method using proved oil and gas
reserves as audited or prepared by independent petroleum engineers. Costs that
we amortize include:
o all capitalized costs (less accumulated amortization and impairment);
o the estimated future expenditures (based on current costs) to be
incurred in developing proved reserves; and
o estimated dismantlement, restoration and abandonment costs.
You should read the following discussion of the results of operations for
the three months ended March 31, 2003 and 2002 and the financial condition as of
March 31, 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 MARCH 31, 2003 AND 2002
Our results of operations for the three months ended March 31, 2003
primarily reflected the results for Benton-Vinccler in Venezuela, which
accounted for all of our production and oil sales revenue. As a result of
national civil work stoppage, production halted on December 21, 2002 and resumed
on February 8, 2003. Oil revenue per barrel increased 43 percent (from $10.73 in
2002 to $15.34 in 2003) and oil sales quantities decreased 52 percent (from 2.5
million barrels "MMBbls" of oil in 2002 to 1.2 MMBbls of oil in 2003).
Our revenues decreased $8.4 million, or 45 percent, during the three months
ended March 31, 2003 compared with 2002. This was due to decreased sales
quantities from the national civil work stoppage offset by higher world crude
oil prices. Our sales quantities for the three months ended March 31, 2003 from
Venezuela were 13,600 barrels of oil per day "BOPD" compared with 28,200 BOPD
for the three months ended March 31, 2002.
Our operating expenses decreased $0.9 million, or 12 percent, during the
three months ended March 31, 2003 compared with the three months ended March 31,
2002. This was primarily due to the national work stoppage. Depletion,
depreciation and amortization decreased $3.9 million, or 53 percent, during the
three months ended March 31, 2003 compared with the three months ended 2002 due
to decreased production at the South Monagas Unit. Depletion expense per barrel
of oil produced from Venezuela during the three months ended March 31, 2003 was
$2.57 compared with $2.37 during the three months ended 2002. General and
administrative expenses remained flat during the three months ended March 31,
2003 compared with the three months ended 2002. Taxes other than on income
increased during the three months ended March 31, 2003 compared with the three
months ended 2002.
Interest expense decreased $3.8 million, or 59 percent, during the three
months ended March 31, 2003 compared with the three months ended 2002. This was
primarily due to the repurchase of debt. Net gain on exchange rates decreased
$1.5 million for the three months ended March 31, 2003 compared with the three
months ended 2002. This was due to Bolivar currency controls discussed below. We
realized income before income taxes and minority interest of $3.1 million during
the three months ended March 31, 2003 compared with income of $4.6 million in
the three months ended 2002. Income tax expense declined $0.8 million due to the
lower pre-tax income. The effective tax rate deceased from 39 to 35 percent in
the three months ended March 31, 2002, compared to March 31, 2003. The decrease
was due to income taxes incurred on profitable foreign jurisdictions being lower
and reduction in U.S. losses where no tax benefit is recorded. The income
attributable to the minority interest decreased $0.5 million for the three
months ended March 31, 2003 compared with the three months ended 2002. This
decrease was due to the decreased production of Benton-Vinccler.
Equity in net earnings of affiliated companies decreased $16.7 million,
during the three months ended March 31, 2003 compared with the three months
ended 2002. Equity earnings included our share of a $17.0 million full cost
ceiling test impairment (write-down). See Note 7 - Russian Operations. The three
months ended March 31, 2002 included a loss of $0.3 million on Arctic Gas.
21
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. 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 $88.8 million cash and marketable securities 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.
22
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.
OIL PRICES
As an independent oil producer, our revenue, other income and equity
earnings and profitability, reserve values, access to capital and future rate of
growth are substantially dependent upon the prevailing prices of crude oil and
natural gas. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond our control. Historically, prices received
for oil production have been volatile and unpredictable, and such volatility is
expected to continue. Through February 14, 2003, we utilized a costless collar
hedge transaction with respect to a portion of our oil production to achieve a
more predictable cash flow, establish an acceptable rate of return on our South
Monagas capital program, as well as to reduce our exposure to price
fluctuations. Benton-Vinccler has hedged a portion of its 2003 oil production by
purchasing a WTI crude oil "put" to protect its 2003 cash flow. Because gains or
losses associated with hedging transactions are included in oil sales when the
hedged production is delivered, such gains and losses are generally offset by
similar changes in the realized prices of the commodities. See Note 1 -
Derivatives and Hedging for a complete discussion of our derivative activity.
INTEREST RATES
Total long-term debt and the current portion of long-term debt at March
31, 2003 of $103.8 million consisted of fixed-rate senior unsecured notes
maturing in 2007 ($85.0 million) and $18.8 million U.S. Dollar denominated loans
of Benton-Vinccler. A hypothetical 10 percent adverse change in the interest
rate would not have had a material affect on our results of operations.
FOREIGN EXCHANGE
For the Venezuelan operations, oil and gas sales are received in U.S.
dollars under a contract in effect through 2012; expenditures are both in U.S.
dollars and local currency. For Geoilbent, a majority of the oil sales are
received in Rubles; expenditures are both in U.S. dollars and local currency,
although a larger percentage of the expenditures are in local currency. We have
utilized no currency hedging programs to mitigate any risks associated with
operations in these countries, and therefore our financial results are subject
to favorable or unfavorable fluctuations in exchange rates and inflation in
these countries. Venezuela has recently imposed currency exchange controls (see
Item 2. Capital Resources and Liquidity above).
POLITICAL RISK
The stability of government in Venezuela and the government's
relationship with the state-owned national oil company, PDVSA, remain
significant risks for our company. PDVSA is the sole purchaser of all Venezuelan
oil and gas production. From December 14, 2002 through February 6, 2003, no
sales were made because of PDVSA's inability to accept our oil due to the
national civil work stoppage. As a result, sales in 2003 were reduced by an
estimated 1.2 million barrels. While the situation has stabilized and production
is returning to normal, there continues to be political and economic uncertainty
that could lead to another disruption of our sales. As a result of the national
civil work stoppage, the Government of Venezuela terminated several thousand
PDVSA employees and announced a decentralization of PDVSA's operations. While
the effect of these changes cannot be predicted, it could adversely affect
PDVSA's ability to manage its contracts and meet its obligations with its
suppliers and vendors, such as Benton-Vinccler. However, we believe that PDVSA
is committed to building its production levels back to full capacity and
returning to more normalized business relations with its customers and
suppliers. As a result of the situation in PDVSA, its February 2003 payment to
Benton-Vinccler for crude delivered in the fourth quarter 2002 was late by seven
days. While we have substantial cash reserves to withstand a future disruption,
a prolonged loss of sales or a failure or delay by PDVSA to pay our invoices
could have a material adverse effect on our financial condition.
23
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 March 31, 2003, 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 and there were no significant changes in
internal controls or factors that could significantly alter their evaluation.
24
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.
ITEM 2. CHANGES IN SECURITIES
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
See Note 7 - Russian Operations with respect to a potential
loan default by Geoilbent.
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
3.1 (i) Amended and Restated Certificate of Incorporation of
Benton Oil and Gas Company.
(ii) Restated By-Laws as of May 14, 2002. (Incorporated
by reference to Exhibits 3.1(i) and (ii) to our Form
10-Q filed August 12, 2002, File No. 1-10762).
10.1 Amended and Restated Employment Agreement dated
February 20, 2003 between Harvest Natural Resources,
Inc. and Peter J. Hill.
10.2 Amended and Restated Employment Agreement dated
February 20, 2003 between Harvest Natural Resources,
Inc. and Steven W. Tholen.
10.3 Amended and Restated Employment Agreement dated
February 20, 2003 between Harvest Natural Resources,
Inc. and Kerry R. Brittain.
10.4 Amended and Restated Employment Agreement dated
February 20, 2003 between Harvest Natural Resources,
Inc. and Kurt A. Nelson.
(b) Reports on Form 8-K
On January 24, 2003, we filed an 8-K for a press release dated
January 23, 2003 updating our December 2002 Venezuelan sales.
On February 14, 2003, we filed an 8-K for a press release
dated February 14, 2003 announcing the restart of production
and sales in Venezuela.
On February 27, 2003, we filed an 8-K for a press release
dated February 27, 2003 announcing fourth quarter and calendar
year 2002 results.
25
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: May 9, 2003 By: /S/Peter J. Hill
-------------------------------------
Peter J. Hill
President and Chief Executive Officer
Dated: May 9, 2003 By: /S/Steven W. Tholen
-------------------------------------
Steven W. Tholen
Senior Vice President,
Chief Financial Officer and Treasurer
26
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 annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c. presented in this 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: May 9, 2003
/s/ Peter J. Hill
-------------------------------------
Peter J. Hill
President and Chief Executive Officer
27
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 annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c. presented in this 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: May 9, 2003
/s/ Steven W. Tholen
-------------------------------------
Steven W. Tholen
Senior Vice President,
Chief Financial Officer and Treasurer
28
EXHIBIT INDEX
3.1 (i) Amended and Restated Certificate of Incorporation of
Benton Oil and Gas Company.
(ii) Restated By-Laws as of May 14, 2002. (Incorporated
by reference to Exhibits 3.1(i) and (ii) to our Form
10-Q filed August 12, 2002, File No. 1-10762).
10.1 Amended and Restated Employment Agreement dated
February 20, 2003 between Harvest Natural Resources,
Inc. and Peter J. Hill.
10.2 Amended and Restated Employment Agreement dated
February 20, 2003 between Harvest Natural Resources,
Inc. and Steven W. Tholen.
10.3 Amended and Restated Employment Agreement dated
February 20, 2003 between Harvest Natural Resources,
Inc. and Kerry R. Brittain.
10.4 Amended and Restated Employment Agreement dated
February 20, 2003 between Harvest Natural Resources,
Inc. and Kurt A. Nelson.
99.1 Persuant to Section 906 of the Sarbanes-Oxley Act of
2002 - CEO and CFO certificates