<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
Quarterly Report Under Section 13 or 15(d)
[X] of the Securities Exchange Act of 1934
For the Quarterly Period Ended March 31, 1999 or
Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from_____ to _____
COMMISSION FILE NO. 1-10762
------------------
BENTON OIL AND GAS COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 77-0196707
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
6267 CARPINTERIA AVE., SUITE 200
CARPINTERIA, CALIFORNIA 93013
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (805) 566-5600
--------------
Indicate by check mark whether the Registrant (1) has
filed all reports required to be filed by Section 13
or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter
period that the Registrant was required to file such
reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
---- ----
--------------
At May 12, 1999, 29,576,966 shares of the
Registrant's Common Stock were outstanding.
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2
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
<TABLE>
<CAPTION>
Page
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PART I. FINANCIAL INFORMATION
<S> <C>
Item 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets at March 31, 1999 (Unaudited)
and December 31, 1998....................................................................3
Consolidated Statements of Operations for the Three
Months Ended March 31, 1999 and 1998 (Unaudited).........................................4
Consolidated Statements of Cash Flows for the Three
Months Ended March 31, 1999 and 1998 (Unaudited).........................................5
Notes to Consolidated Financial Statements......................................................7
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS..............................................................17
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS................................................................................24
Item 2. CHANGES IN SECURITIES............................................................................24
Item 3. DEFAULTS UPON SENIOR SECURITIES..................................................................24
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............................................24
Item 5. OTHER INFORMATION................................................................................24
Item 6. EXHIBITS AND REPORTS ON FORM 8-K.................................................................24
Signatures...............................................................................................................25
</TABLE>
<PAGE> 3
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
<TABLE>
<CAPTION>
MARCH 31,
1999 DECEMBER 31,
(UNAUDITED) 1998
----------- ------------
ASSETS
- ------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 12,422 $ 18,147
Restricted cash 12 12
Marketable securities 29,782 41,173
Accounts and notes receivable:
Accrued oil and gas revenue 18,198 17,307
Joint interest and other, net 9,161 12,482
Prepaid expenses and other 3,732 3,688
--------- ---------
TOTAL CURRENT ASSETS 73,307 92,809
RESTRICTED CASH 65,798 65,670
OTHER ASSETS 11,369 11,725
DEFERRED INCOME TAXES 2,976 2,976
INVESTMENT IN AND ADVANCES TO AFFILIATED COMPANY 18,577 11,975
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of $39,873 and
$35,228 excluded from amortization in 1999 and 1998, respectively) 499,252 483,494
Furniture and fixtures 9,331 9,608
--------- ---------
508,583 493,102
Accumulated depletion, impairment and depreciation (344,560) (339,636)
--------- ---------
164,023 153,466
--------- ---------
$ 336,050 $ 338,621
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other $ 8,680 $ 10,014
Accrued interest payable 11,744 5,527
Accrued expenses 20,622 19,342
Income taxes payable 2,298 1,847
Current portion of long term debt 136 215
--------- ---------
TOTAL CURRENT LIABILITIES 43,480 36,945
LONG TERM DEBT 287,614 288,212
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST 630 475
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 29,627 shares at March 31, 1999 and
December 31, 1998 296 296
Additional paid-in capital 147,054 147,054
Retained deficit (140,232) (131,569)
Treasury stock, at cost, 50 shares (699) (699)
Employee note receivable, net (2,093) (2,093)
--------- ---------
TOTAL STOCKHOLDERS' EQUITY 4,326 12,989
--------- ---------
$ 336,050 $ 338,621
========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
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4
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data, unaudited)
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
----------------------------
1999 1998
------------- ------------
<S> <C> <C>
REVENUES:
Oil sales $ 17,971 $ 28,501
Net gain on exchange rates 1,415 613
Investment earnings and other 2,654 4,144
-------- --------
22,040 33,258
-------- --------
EXPENSES:
Lease operating costs and production taxes 11,131 13,241
Depletion, depreciation and amortization 5,367 11,066
Write-down of oil and gas properties -- 17,500
General and administrative 5,567 5,406
Interest 7,843 8,080
-------- --------
29,908 55,293
-------- --------
LOSS BEFORE INCOME TAXES
AND MINORITY INTEREST (7,868) (22,035)
INCOME TAX EXPENSE (BENEFIT) 640 (670)
-------- --------
LOSS BEFORE MINORITY INTEREST (8,508) (21,365)
MINORITY INTEREST 155 (379)
-------- --------
NET LOSS $ (8,663) $(20,986)
======== ========
NET LOSS PER COMMON SHARE:
Basic $ (0.29) $ (0.71)
======== ========
Diluted $ (0.29) $ (0.71)
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
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5
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands, unaudited)
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
----------------------------
1999 1998
--------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss $ (8,663) $(20,986)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion, depreciation and amortization 5,367 11,066
Write-down of oil and gas properties -- 17,500
Amortization of financing costs 393 284
Loss on disposal of assets 38 --
Minority interest in undistributed earnings of subsidiary 155 (379)
Deferred income taxes -- (1,413)
Changes in operating assets and liabilities:
Accounts receivable 2,430 14,608
Prepaid expenses and other (44) 112
Accounts payable (1,334) (1,247)
Accrued interest payable 6,217 6,130
Accrued expenses 1,280 (774)
Income taxes payable 451 (3,423)
-------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 6,290 21,478
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment (15,906) (39,333)
Investment in and advances to affiliated company (6,602) --
Increase in restricted cash (128) (78)
Purchase of marketable securities (12,644) (41,404)
Maturities of marketable securities 24,035 67,308
-------- --------
NET CASH USED IN INVESTING ACTIVITIES (11,245) (13,507)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from exercise of stock options and warrants -- 394
Proceeds from issuance of short term borrowings and notes payable 20 3,468
Payments on short term borrowings and notes payable (697) (27)
Increase in other assets (93) (24)
-------- --------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (770) 3,811
-------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (5,725) 11,782
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 18,147 11,940
======== ========
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 12,422 $ 23,722
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for interest expense $ 1,638 $ 1,558
======== ========
Cash paid during the period for income taxes $ 781 $ 2,401
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
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6
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During 1996 and 1997, the Company incurred $4.1 million in financing costs
related to the establishment of the EBRD financing (see Note 6). In 1998, under
an agreement with EBRD, GEOILBENT's board ratified an agreement to reimburse the
Company for $2.6 million of such costs, and accordingly, during the three months
ended March 31, 1998, the Company recorded these costs as an account receivable
from GEOILBENT.
See accompanying notes to consolidated financial statements.
<PAGE> 7
7
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
THREE MONTHS ENDED MARCH 31, 1999 (UNAUDITED)
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Benton Oil and Gas Company (the "Company") engages in the exploration,
development, production and management of oil and gas properties. The Company
conducts its business in Venezuela, Russia, the United States, China, Jordan and
Senegal.
The consolidated financial statements include the accounts of the Company and
its subsidiaries. The Company's investment in GEOILBENT, its Russian joint
venture, is accounted for using proportionate consolidation based on the
Company's ownership interest. The Company's investment in Severneftegaz, a
Russian open joint stock company, is accounted for using the equity method
because of the significant influence the Company exercises over its operations
and management. All intercompany profits, transactions and balances have been
eliminated. The Company accounts for its investment in GEOILBENT and
Severneftegaz based on a fiscal year ending September 30.
During 1998, the Company instituted a capital expenditure program which
minimized expenditures to those that the Company believed were necessary in
order to maintain current producing properties.
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuation in response to change in supply, market uncertainty and a variety of
factors beyond the Company's control.
The Company believes its current cash and cash to be provided by operating
activities will be sufficient to meet the Company's liquidity needs for routine
operations and to service its outstanding debt through 1999. The Company
continues to evaluate and review strategic alternatives and has engaged J.P.
Morgan Securities, Inc. to advise the Company related to these alternatives. If
oil market conditions worsen or future cash requirements are greater than the
Company's financial resources, the Company intends to pursue strategic joint
ventures or alliances with other industry partners, sell property interests,
merge or combine with another entity, or issue debt or equity securities.
INTERIM REPORTING
In the opinion of the Company, 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,
1999, and the results of operations for the three month periods ended March 31,
1999 and 1998. The unaudited financial statements are presented in accordance
with the requirements of Form 10-Q and do not include all disclosures normally
required by generally accepted accounting principles. Reference should be made
to the Company's consolidated financial statements and notes thereto included in
the Company's Annual Report on Form 10-K for the year ended December 31, 1998
for additional disclosures, including a summary of the Company's accounting
policies.
The results of operations for the three month period ended March 31, 1999 are
not necessarily indicative of the results to be expected for the full year.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles 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.
Actual results could differ from those estimates.
ACCOUNTS AND NOTES RECEIVABLE
The Company's allowance for doubtful accounts related to employee notes and
accounts receivable and other accounts receivable was $3.2 million and $0.4
million at March 31, 1999 and 1998, respectively (see Note 12).
<PAGE> 8
8
MINORITY INTERESTS
The Company records a minority interest attributable to the minority
shareholders of its subsidiaries. The minority interests in net income and
losses are generally subtracted or added to arrive at consolidated net income.
However, during the three month period ended March 31, 1999, losses attributable
to the minority shareholder of Benton-Vinccler, a subsidiary owned 80% by the
Company, exceeded its interest in equity capital. Accordingly, $0.8 million of
Benton-Vinccler's loss for the period attributable to the minority shareholders
has been included in the consolidated net loss of the Company.
MARKETABLE SECURITIES
Marketable securities are carried at amortized cost. The marketable securities
the Company may purchase are limited to those defined as Cash Equivalents in the
indentures for its senior unsecured notes. Cash Equivalents may be comprised of
high-grade debt instruments, demand or time deposits, bankers' acceptances and
certificates of deposit or acceptances of large U.S. financial institutions and
commercial paper of highly rated U.S. corporations, all having maturities of no
more than 180 days. The Company's marketable securities at cost, which
approximates fair value, consisted of $29.8 million in commercial paper at March
31, 1999 and $41.2 million in commercial paper at December 31, 1998.
COMPREHENSIVE INCOME
Statement of Financial Accounting Standards No. 130 ("SFAS 130") requires that
all items that are required to be recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements. However, the
Company did not have any items of other comprehensive income during the three
months ended March 31, 1999 or March 31, 1998 and, in accordance with SFAS 130,
has not provided a separate statement of comprehensive income.
EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128 ("SFAS 128") "Earnings per Share." SFAS
128 replaces the presentation of primary earnings per share with a presentation
of basic earnings per share based upon the weighted average number of common
shares for the period. It also requires dual presentation of basic and diluted
earnings per share for companies with complex capital structures. SFAS 128 was
adopted by the Company in December 1997, and earnings per share for all prior
periods have been restated. The numerator (income), denominator (shares) and
amount of the basic and diluted earnings per share computations for income were
(in thousands, except per share amounts):
<TABLE>
<CAPTION>
AMOUNT PER
LOSS SHARES SHARE
------------- ------------ ------------
FOR THE THREE MONTHS ENDED MARCH 31, 1999
-----------------------------------------
<S> <C> <C> <C>
BASIC EPS
Loss attributable to common stockholders $ (8,663) 29,577 $(0.29)
======== ====== ======
DILUTED EPS
Loss attributable to common stockholders $ (8,663) 29,577 $(0.29)
======== ====== ======
FOR THE THREE MONTHS ENDED MARCH 31, 1998
-----------------------------------------
BASIC EPS
Loss attributable to common stockholders $(20,986) 29,496 $(0.71)
======== ====== ======
DILUTED EPS
Loss attributable to common stockholders $(20,986) 29,496 $(0.71)
======== ====== ======
</TABLE>
An aggregate 5.9 million and 4.9 million options and warrants were excluded from
the earnings per share calculations because they were anti-dilutive for the
three months ended March 31, 1999 and 1998, respectively.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for oil and gas
properties. Accordingly, all costs associated with the acquisition, exploration,
and development of oil and gas reserves are capitalized as incurred, including
<PAGE> 9
9
exploration overhead of $0.6 million for the three months ended March 31, 1999
and 1998 and capitalized interest of $0.4 million for the three months ended
March 31, 1999. Only overhead which is directly identified with acquisition,
exploration or development activities is capitalized. Interest is capitalized on
significant investments in unproved properties that are excluded from depletion,
depreciation and amortization and on which exploration activities are in
progress. All costs related to production, general corporate overhead and
similar activities are expensed as incurred. The costs of oil and gas properties
are accumulated in cost centers on a country by country basis, subject to a cost
center ceiling (as defined by the Securities and Exchange Commission). At March
31, 1998, the Company recognized a write-down of oil and gas properties in the
Venezuela cost center of $17.5 million pursuant to the ceiling limitation as a
result of declines in world crude oil prices.
All capitalized costs of oil and gas properties (excluding unevaluated property
acquisition and exploration costs) and the estimated future costs of developing
proved reserves, are depleted over the estimated useful lives of the properties
by application of the unit-of-production method using only proved oil and gas
reserves. Excluded costs attributable to the Russia, China and other cost
centers at March 31, 1999 were $4.7 million, $24.6 million, and $10.6 million,
respectively. Excluded costs attributable to the Russia, China and other cost
centers at December 31, 1998 were $4.3 million, $20.5 million and $10.4 million,
respectively. Depletion expense attributable to the Venezuela and Russia cost
centers for the three months ended March 31, 1999 was $4.2 million and $0.7
million ($1.57 and $2.10 per equivalent barrel), respectively. Depletion expense
attributable to the Venezuela and Russia cost centers for the three months ended
March 31,1998 was $10.3 million and $0.5 million ($2.83 and $3.67 per equivalent
barrel), respectively. Depreciation of furniture and fixtures is computed using
the straight-line method, with depreciation rates based upon the estimated
useful life applied to the cost of each class of property. Depreciation expense
was $0.4 million and $0.3 million for the three months ended March 31, 1999 and
1998, respectively.
RECLASSIFICATIONS
Certain items in 1998 have been reclassified to conform to the 1999 financial
statement presentation.
NOTE 2 - LONG TERM DEBT
Long term debt consists of the following (in thousands):
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998
--------- ------------
<S> <C> <C>
Senior unsecured notes with interest at 9.375%.
See description below. $ 105,000 $ 105,000
Senior unsecured notes with interest at 11.625%.
See description below. 125,000 125,000
Benton-Vinccler credit facility with interest at
LIBOR plus 6.125%. Collateralized by a time deposit
of the Company earning approximately LIBOR plus 5.75%.
See description below. 50,000 50,000
Reserve-based loans with average interest
rate of LIBOR plus 5.25%. See description below. 6,453 6,453
GEOILBENT credit facility collateralized by a time deposit of the
Company earning approximately 5.6%. See description below. 930 1,624
Other 367 350
--------- ---------
287,750 288,427
Less current portion 136 215
--------- ---------
$ 287,614 $ 288,212
========= =========
</TABLE>
In November 1997, the Company issued $115 million in 9.375% senior unsecured
notes due November 1, 2007, of which the Company subsequently repurchased $10
million at their par value. In May 1996, the Company issued $125 million in
11.625% senior unsecured notes due May 1, 2003. Interest on the notes is due May
1 and November 1 of each year. The indenture agreements provide for certain
limitations on liens, additional indebtedness, certain investments and capital
expenditures, dividends, mergers and sales of assets. At March 31, 1999, the
Company was in compliance with all covenants of the indentures.
In August 1996, Benton-Vinccler entered into a $50 million, long term credit
facility with Morgan Guaranty Trust Company of New York ("Morgan Guaranty") to
repay the balance outstanding under a short term credit facility and to repay
certain advances received from the Company. The credit facility is
collateralized in full by a time deposit of the
<PAGE> 10
10
Company, bears interest at LIBOR plus 6.125% and matures in August 2001. The
Company receives interest on its time deposit and a security fee on the
outstanding principal of the loan, for a combined total of approximately LIBOR
plus 5.75%. The loan arrangement contains no restrictive covenants and no
financial ratio covenants.
As of March 31, 1999, GEOILBENT (owned 34% by the Company) has borrowed $19.0
million under parallel reserve-based loan agreements with the European Bank for
Reconstruction and Development ("EBRD") and International Moscow Bank ("IMB").
EBRD and IMB have agreed to lend up to a total of $65 million to GEOILBENT based
on achieving certain reserve and production milestones. Under these loan
agreements, the Company and other shareholders of GEOILBENT have significant
management and business support obligations. Each shareholder is jointly and
severally liable to EBRD and IMB for any losses, damages, liabilities, costs,
expenses and other amounts suffered or sustained arising out of any breach by
any shareholder of its support obligations. The loans bear an average interest
rate of LIBOR plus 5.25% payable on January 27 and July 27 each year. Principal
payments will be due in varying installments every six months beginning January
27, 2000 until July 27, 2004. The loan agreements require that GEOILBENT meet
certain financial ratios and covenants, including a minimum current ratio, and
provides for certain limitations on liens, additional indebtedness, certain
investment and capital expenditures, dividends, mergers and sales of assets. The
Company's share of the amounts borrowed under the loan agreements was $6.5
million at March 31, 1999 and December 31, 1998, respectively.
In October 1995, GEOILBENT entered into an agreement with Morgan Guaranty for a
credit facility under which the Company provides cash collateral for the loans
to GEOILBENT. The credit facility is renewable annually. Loans outstanding under
the credit facility bear interest at either LIBOR plus 0.75%, subject to certain
adjustments, or the Morgan Guaranty prime rate plus 2%, whichever is selected at
the time a loan is made. In conjunction with GEOILBENT's reserve-based loan
agreements with the EBRD and IMB, repayment of the credit facility is
subordinated to payments due to the EBRD and IMB and, accordingly, the credit
facility is classified as long term. However, during the quarter ended March 31,
1999, EBRD and IMB consented to the repayment of $2.0 million ($0.7 million to
the Company) in exchange for the Company's capital contribution to GEOILBENT of
$2.0 million. The credit facility contains no restrictive covenants and no
financial ratio covenants.
NOTE 3 - COMMITMENTS AND CONTINGENCIES
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties and that it paid a
price in excess of the fair value of the property. A trial date has been
scheduled for October 25, 1999 and discovery is ongoing, but incomplete. The
Company intends to vigorously contest the suit, and in management's opinion it
is too early to assess the probability of an unfavorable outcome.
In the normal course of its business, the Company may periodically become
subject to actions threatened or brought by its investors or partners in
connection with the operation or development of its properties or the sale of
securities. Prior to 1992, the Company was engaged in the formation and
operation of oil and gas limited partnership interests. In 1992, the Company
ceased raising funds through such sales. Certain limited partners in limited
partnerships sponsored by the Company have brought an action against the Company
in connection with the Company's operation of the limited partnerships as
managing general partner. The plaintiffs seek actual and punitive damages for
alleged actions and omissions by the Company in operating the partnerships and
alleged misrepresentations made by the Company in selling the limited
partnership interests. In May 1995, the Company agreed to a binding arbitration
proceeding with respect to such claims. Based on the plaintiffs' failure to
pursue the arbitration, the American Arbitration Association dismissed the case
on November 25, 1998, but gave the plaintiffs until February 23, 1999, to obtain
a court order compelling arbitration. To date, the plaintiffs have neither
sought nor obtained such a court order.
The Company is also subject to ordinary litigation that is incidental to its
business, none of which are expected to have a material adverse effect on the
Company's financial statements.
In May 1996, the Company entered into an agreement with Morgan Guaranty which
provided for an $18 million cash collateralized 5-year letter of credit to
secure the Company's performance of the minimum exploration work program
required in the Delta Centro Block in Venezuela. In December 1998, the letter of
credit was reduced to $11.2 million as a result of expenditures made related to
the exploration work program.
<PAGE> 11
11
The Company has employment contracts with four senior management personnel which
provide for annual base salaries, bonus compensation and various benefits. The
contracts provide for the continuation of salary and benefits for the respective
terms of the agreements in the event of termination of employment without cause.
These agreements expire at various times from July 10, 1999 to June 1, 2001. The
Company has also entered into employment agreements with eight individuals,
which provide for certain severance payments in the event of a change of control
of the Company and subsequent termination by the employees for good reason.
The Company has entered into various exploration and development contracts in
various countries which require minimum expenditures, some of which required
that the Company secure its commitments by providing letters of credit. The
Company has also entered into equity acquisition agreements in Russia which call
for the Company to provide or arrange for certain amounts of credit financing in
order to remove sale and transfer restrictions on the equity acquired or to
maintain ownership in such equity.
In 1998, the Company entered into a 15-year lease agreement for office space in
Carpinteria, California. The Company has leased 50,000 square feet for
approximately $74,000 per month with annual rent adjustments based on certain
changes in the Consumer Price Index. The Company has entered into a sublease
agreement for a portion of the office space which is not currently needed for
operations. The Company has also entered into a sublease agreement for the
office space that it previously occupied. Rents for the subleases approximate
the Company's lease costs of these facilities.
NOTE 4 - TAXES ON INCOME
At December 31, 1998, the Company had, for federal income tax purposes,
operating loss carryforwards of approximately $90 million expiring in the years
2003 through 2018. If the carryforwards are ultimately realized, approximately
$13 million will be credited to additional paid-in capital for tax benefits
associated with deductions for income tax purposes related to stock options.
During the three months ended March 31, 1999, the Company recorded deferred tax
assets generated from current period operating losses and a valuation allowance
of $2.9 million.
The Company does 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 the Company's ongoing business.
NOTE 5 - OPERATING SEGMENTS
The Company regularly allocates resources to and assesses the performance of its
operations by segments that are organized by unique geographic and operating
characteristics. The segments are organized in order to manage regional
business, currency and tax related risks and opportunities. Revenues from the
Venezuela and Russia operating segments are derived primarily from the
production and sale of oil. Revenues from USA and Other are derived primarily
from interest earnings on various investments and consulting revenues.
Operations included under the heading "USA and Other" include corporate
management, exploration activities, cash management and financing activities
performed in the United States and other countries which do not meet the
requirements for separate disclosure. All intersegment revenues, expenses and
receivables are eliminated in order to reconcile to consolidated totals.
Corporate general and administrative and interest expenses are included in the
USA and Other segment and are not allocated to other operating segments. The
Company's investment in Severneftegaz has been included in the Russia operating
segment.
<PAGE> 12
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<TABLE>
<CAPTION>
INTER-
THREE MONTHS ENDED USA AND SEGMENT
MARCH 31, 1999 (in thousands) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- --------------------------------- --------- --------- --------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenue:
Oil sales $ 16,090 $ 1,881 -- -- $ 17,971
Net gain on exchange rates 256 1,027 $ 132 -- 1,415
Investment earnings and other 121 217 2,597 $ (281) 2,654
Intersegment revenues -- -- 1,609 (1,609) --
--------- --------- --------- --------- ---------
Total revenues 16,467 3,125 4,338 (1,890) 22,040
--------- --------- --------- --------- ---------
Expenses:
Lease operating costs and
production taxes 10,015 948 168 -- 11,131
Depletion, depreciation and
amortization 4,429 700 238 -- 5,367
General and administrative 1,772 343 3,452 -- 5,567
Interest 1,765 361 5,998 (281) 7,843
Intersegment expenses 1,609 -- -- (1,609) --
--------- --------- --------- --------- ---------
Total expenses 19,590 2,352 9,856 (1,890) 29,908
--------- --------- --------- --------- ---------
Income (loss) before income taxes (3,123) 773 (5,518) -- (7,868)
Income tax expense (benefit) 582 (113) 171 -- 640
--------- --------- --------- --------- ---------
Operating segment income (loss) (3,705) 886 (5,689) -- (8,508)
Minority interest 155 -- -- -- 155
--------- --------- --------- --------- ---------
Net income (loss) $ (3,860) $ 886 $ (5,689) -- $ (8,663)
========= ========= ========= ========= =========
Capital expenditures $ 10,610 $ 907 $ 4,389 -- $ 15,906
========= ========= ========= ========= =========
Total assets $ 106,807 $ 72,679 $ 232,240 $ (75,676) $ 336,050
========= ========= ========= ========= =========
</TABLE>
<PAGE> 13
13
<TABLE>
<CAPTION>
INTER-
THREE MONTHS ENDED USA AND SEGMENT
MARCH 31, 1998 (in thousands) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- ---------------------------------------- ---------- --------- --------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues:
Oil sales $ 27,022 $ 1,479 -- -- $ 28,501
Net gain on exchange rates 546 67 -- -- 613
Investment earnings and other 217 96 $ 4,009 $ (178) 4,144
Intersegment revenues -- -- 2,638 (2,638) --
--------- --------- --------- --------- ---------
Total revenues 27,785 1,642 6,647 (2,816) 33,258
--------- --------- --------- --------- ---------
Expenses:
Lease operating costs and production
taxes 11,659 1,571 11 -- 13,241
Depletion, depreciation and
amortization 10,478 468 120 -- 11,066
General and administrative 1,794 453 3,159 -- 5,406
Interest 1,770 105 6,383 (178) 8,080
Intersegment expenses 2,638 -- -- (2,638) --
--------- --------- --------- --------- ---------
Total expenses 28,339 2,597 9,673 (2,816) 37,793
--------- --------- --------- --------- ---------
Loss before income taxes (554) (955) (3,026) -- (4,535)
Income tax expense (benefit) (976) 74 232 -- (670)
--------- --------- --------- --------- ---------
Operating segment income (loss) 422 (1,029) (3,258) -- (3,865)
Write-down and impairment of oil and
gas properties (17,500) -- -- -- (17,500)
Minority interest (379) -- -- -- (379)
--------- --------- --------- --------- ---------
Net loss $ (16,699) $ (1,029) $ (3,258) -- $ (20,986)
========= ========= ========= ========= =========
Capital expenditures $ 30,457 $ 3,996 $ 4,880 -- $ 39,333
========= ========= ========= ========= =========
Total assets $ 254,460 $ 47,357 $ 301,571 $ (37,368) $ 566,020
========= ========= ========= ========= =========
</TABLE>
NOTE 6 - RUSSIAN OPERATIONS
Beginning in October 1997 and continuing through December 1998, GEOILBENT
borrowed $10.2 million and $8.8 million, respectively, under parallel
reserve-based loan agreements with the European Bank for Reconstruction and
Development and International Moscow Bank. EBRD and IMB have agreed to lend up
to a total of $65 million to GEOILBENT based on achieving certain reserve and
production milestones. The proceeds from the loans will be used by GEOILBENT to
develop the North Gubkinskoye Field in West Siberia, Russia. At March 31, 1999
and December 31, 1998, the Company's share of borrowings under these agreements
was $6.5 million. In 1999, GEOILBENT borrowed an additional $10 million ($3.4
million to the Company). Because the Company accounts for its investment in
GEOILBENT based on a fiscal year ending September 30, the 1999 borrowings will
be reflected in the Company's consolidated financial statements in the quarters
ending June 30, 1999 and September 30, 1999. Additionally, during 1998 a
subsidiary of the Company recorded an account receivable for pipe it purchased
for $5.0 million and sold at cost to GEOILBENT for use in the development of the
field. The portion of the receivable not eliminated in consolidation is included
in accounts receivable, joint interest and other. During 1996 and 1997, the
Company incurred $4.1 million in financing costs related to the establishment of
the EBRD financing, which are recorded in other assets and are subject to
amortization over the life of the facility. In 1998, under an agreement with
EBRD, GEOILBENT's board ratified an agreement to reimburse the Company for $2.6
million of such costs. However, due to GEOILBENT's need for oil and gas
investment and the declining prices for crude oil, in the second quarter of 1998
the Company agreed to defer payment of those reimbursements.
Excise, pipeline and other taxes (including a new oil export tariff introduced
in 1999) continue to be levied on all oil producers and certain exporters.
Although the Russian regulatory environment has become less volatile, the
Company is unable to predict the impact of taxes, duties and other burdens for
the future.
<PAGE> 14
14
In April 1998, the Company signed an agreement to earn a 40% equity interest in
Severneftegaz. Severneftegaz owns the exclusive rights to evaluate, develop and
produce the natural gas, condensate, and oil reserves in the Samburg and
Yevo-Yakha license blocks in West Siberia. The two blocks comprise 837,000 acres
within and adjacent to the Urengoy Field, Russia's largest producing natural gas
field. Pursuant to a Cooperation Agreement between the Company and
Severneftegaz, the Company will earn a 40% equity interest in exchange for
providing the initial capital needed to achieve natural gas production. The
Company's capital commitment will be in the form of providing or arranging a
$100 million credit facility for the project, the terms of which have yet to be
finalized, which is expected to be disbursed over the initial two-year
development phase. The Company has received voting shares representing a 40%
ownership in Severneftegaz that contain restrictions on their sale and transfer.
A Share Disposition Agreement provides for removal of the restrictions as
disbursements are made under the credit facility. As of March 31, 1999, the
Company had loaned $10.1 million to Severneftegaz pursuant to an interim credit
facility, with interest at LIBOR plus 3%, and had earned the right to remove
restrictions from shares representing an approximate 2.8% equity interest. In
December 1998 and January 1999, the Company purchased shares representing an
additional 15% equity interest not subject to any sale or transfer restrictions.
The Company owned a total of 55% of voting shares of Severneftegaz as of March
31, 1999, of which 17.8% was not subject to any restrictions. Due to the
significant influence it exercises over the operating and financial policies of
Severneftegaz, the Company has accounted for its interest in Severneftegaz using
the equity method. Certain provisions of Russian corporate law would effectively
require minority shareholder consent in the making of new agreements between the
Company and Severneftegaz, or to the changing of any terms in any existing
agreements between the two partners such as the Cooperation Agreement and the
Share Disposition Agreement, including the conditions upon which the
restrictions on the shares could be removed.
NOTE 7 - VENEZUELA OPERATIONS
On July 31, 1992, the Company and its partner, Venezolana de Inversiones y
Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement
to reactivate and further develop three Venezuelan oil fields with Lagoven,
S.A., then one of three exploration and production affiliates of the national
oil company, Petroleos de Venezuela, S.A. ("PDVSA") which have subsequently all
been combined into PDVSA Petroleo y Gas, S.A. (all such parent, subsidiary and
affiliated entities hereinafter referred to as "PDVSA"). The operating service
agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South
Monagas Unit ("Unit"). Under the terms of the operating service agreement,
Benton-Vinccler, C.A. ("Benton-Vinccler"), a corporation owned 80% by the
Company and 20% by Vinccler, is a contractor for PDVSA and is responsible for
overall operations of the Unit, including all necessary investments to
reactivate and develop the fields comprising the 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 (which amount is
periodically adjusted to reflect changes in the average of certain world crude
oil prices). The Venezuelan government maintains full ownership of all
hydrocarbons in the fields.
In January 1996, the Company and its bidding partners, Louisiana Land &
Exploration, which has been subsequently acquired by Burlington Resources, Inc.
("Burlington"), and Norcen Energy Resources, LTD, which has been subsequently
acquired by Union Pacific Resources Group Inc. ("UPR"), were awarded the right
to explore and develop the Delta Centro Block in Venezuela. The contract
requires a minimum exploration work program consisting of completing an 839
kilometer seismic survey and drilling three wells to depths of 12,000 to 18,000
feet within five years. At the time the block was tendered for international
bidding, PDVSA estimated that this minimum exploration work program would cost
$60 million and required that the Company and the other partners each post a
performance surety bond or standby letter of credit for its pro rata share of
the estimated work commitment expenditures. The Company has a 30% interest in
the exploration venture, with Burlington and UPR each owning a 35% interest.
Under the terms of the operating agreement, which establishes the management
company of the project, Burlington will be the operator of the field and,
therefore, the Company will not be able to exercise control of the operations of
the venture. Corporacion Venezolana del Petroleo, S.A., an affiliate of PDVSA,
has the right to obtain a 35% interest in the management company, which dilutes
the voting power of the partners on a pro rata basis. In July 1996, formal
agreements were finalized and executed, and the Company posted an $18 million
standby letter of credit, collateralized in full by a time deposit of the
Company, to secure its 30% share of the minimum exploration work program (see
Note 3). As of March 31, 1999, the Company' share of expenditures to date was
$11.9 million, and the standby letter of credit had been reduced to $11.2
million. During the first quarter of 1999, drilling commenced on the Jarina-1 X,
the first of the Block's exploration wells. The well, which had a planned total
depth of 15,600 feet and was one of several structures identified from the new
3-D seismic data, penetrated a thick potential reservoir sequence,
<PAGE> 15
15
but encountered no commercial hydrocarbons. The Company and its partners
continue to evaluate the remaining leads on the block, including their potential
reserves and risk factors.
NOTE 8 - CHINA OPERATIONS
In December 1996, the Company acquired Benton Offshore China Company, a
privately held corporation headquartered in Denver, Colorado, for 628,142 shares
of common stock and options to purchase 107,571 shares of the Company's common
stock at $7.00 per share, valued in total at $14.6 million. Benton Offshore
China Company's primary asset is a large undeveloped acreage position in the
South China Sea under a petroleum contract with China National Offshore Oil
Corporation ("CNOOC") of the People's Republic of China for an area known as
Wan'An Bei, WAB-21. Benton Offshore China Company will, as a wholly owned
subsidiary of the Company, continue as the operator and contractor of WAB-21.
Benton Offshore China Company has submitted an exploration program and budget to
CNOOC. However, due to certain territorial disputes over the sovereignty of the
contract area, it is unclear when such program will commence.
In October 1997, the Company signed a farmout agreement with Shell Exploration
(China) Limited ("Shell") whereby the Company acquired a 50% participation
interest in Shell's Liaohe area onshore exploration project in northeast China.
Shell holds a petroleum contract with China National Petroleum Corporation
("CNPC") to explore and develop the deep rights in the Qingshui Block, a 563
square kilometer area (approximately 140,000 acres) in the delta of the Liaohe
River. Shell is the operator of the project. In July 1998, the Company paid to
Shell 50% of Shell's prior investment in the Block, which was approximately $4
million ($2 million to the Company). The Company is required to pay 100% of the
first $8 million of the costs for the phase one exploration period, after which
any development costs will be shared equally. If a commercial well results from
phase one and the Company elects to continue to phase two, then the Company will
pay 100% of the first $8 million of the costs of the second phase of the
exploration period, after which any development costs will be shared equally. If
a commercial well does not result from phase one and the Company elects to
continue to phase two, then the Company and Shell will share costs equally. The
Company and Shell will share costs equally for the third exploration phase, if
any. During the first quarter of 1999, drilling commenced on the Qing-22 Deep
well as a part of the phase one exploration period activities. As of March 31,
1999, the Company had incurred $8.2 million related to the farmout agreement.
NOTE 9 - SANTA BARBARA OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy, which held 100%
of these leases. The project area covers the Molino, Gaviota and Caliente
Fields, located approximately 35 miles west of Santa Barbara, California. In
consideration of the 40% participation interest in the leases, the Company
became the operator of the project and paid 100% of the first $3.7 million and
53% of the remainder of the costs of the first well drilled on the block. During
1998, the 2199 #7 exploratory well was drilled to the Gaviota anticline. Drill
stem tests proved to be inconclusive or non-commercial, and the well was
temporarily abandoned for further evaluation. The Company's share of the
drilling and testing of the 2199 #7 well was $8.5 million. In November 1998, the
Company entered into an agreement to acquire Molino Energy's interest in the
leases in exchange for the release of its joint interest billing obligations of
approximately $1.9 million. The agreement to acquire Molino Energy's interest
will be finalized upon the completion of certain lot splits and the assignment
of various permits and rights.
NOTE 10 - JORDAN OPERATIONS
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over approximately eight years. The Company
is obligated to spend $5.1 million in the first exploration phase, which has
been extended to May 2000. If the Company ultimately elects to continue through
phases two and three, it would be obligated to spend an additional $18 million
over the succeeding six years. During the first quarter of 1998, the Company
reentered two wells and tested two different reservoirs. The WS-9 and WS-10
wells did not result in the production of commercial amounts of hydrocarbons.
The Company will continue to reprocess and remap seismic data and conduct
geological studies on the remaining prospectivity of the block. As of March 31,
1999, the Company had incurred $3.7 million related to the PSA.
<PAGE> 16
16
NOTE 11 - SENEGAL OPERATIONS
In December 1997, the Company signed a memorandum of understanding with Societe
des Petroles du Senegal ("Petrosen"), the state oil company of the Republic of
Senegal, to receive a minimum 45% working interest in and to operate the
approximately one million acre onshore Thies Block in western Senegal. In
addition, the Company obtained exclusive rights from Petrosen to evaluate and
reprocess geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea-Bissau border in the south, and to choose
certain blocks for further data acquisition and exploration drilling. The
Company's working interest in any offshore discovery will be 85% with the
remainder held by Petrosen. The Company's $5.4 million work commitment on the
Thies Block, where Petrosen has recently drilled and completed the Gadiaga #2
discovery well, consists of hooking up the existing well, drilling two
additional wells and constructing a 41-kilometer (approximately 25-mile) gas
pipeline to Senegal's main electric generating facility near Dakar. As of March
31, 1999, the Company had incurred $1.8 million related to both the onshore
block and near-offshore acreage.
NOTE 12 - RELATED PARTY TRANSACTIONS
Prior to November 30, 1998 and during 1997 and 1996, the Company made unsecured
loans documented by a promissory note bearing interest at 6% to Mr. A. E.
Benton, its Chief Executive Officer. At December 31,1997 and September 30, 1998,
the balances owed to the Company were $2.0 million and $4.4 million,
respectively. In the fourth quarter of 1998, the Company loaned Mr. Benton an
additional $1.1 million to enable him to reduce and eliminate his outstanding
margin accounts with third parties that were secured by shares of the Company's
stock. The Company then obtained a security interest in those shares of stock,
certain personal real estate and proceeds from certain contractual and stock
option agreements. At December 31, 1998, the $5.5 million owed to the Company by
Mr. Benton, which is documented by a promissory note that bears interest at 6%
and is payable on November 30, 1999, exceeded the value of the collateral,
primarily due to the decline in the price of the Company's stock. As a result,
the Company recorded an allowance for doubtful accounts of $2.9 million.
Measuring the amount of the allowance requires judgments and estimates, and the
amount eventually realized may differ from the estimate. The portion of the note
secured by the Company's stock and stock options has been presented on the
balance sheet as a deduction from stockholders' equity. At March 31, 1999, the
balance owed to the Company by Mr. Benton, including accrued interest and
excluding the allowance for doubtful accounts recorded in 1998, was $5.6
million.
Also during 1997 and 1996, the Company made loans to Mr. M.B. Wray, its Vice
Chairman, and Mr. J.M. Whipkey, its Chief Financial Officer, each loan bearing
interest at 6% and collateralized by a security interest in personal real
estate. At March 31, 1999, the balances owed to the Company by Mr. Wray and Mr.
Whipkey were $0.6 million and $0.5 million, respectively, and at December 31,
1998, the balances owed to the Company by Mr. Wray and Mr. Whipkey were $0.6
million and $0.5 million, respectively. On May 11, 1999, Mr. Wray repaid the
entire balance of principal and interest on his loan.
In addition, receivables from other employees and directors of the Company
totaled $0.6 million at March 31, 1999 and December 31, 1998.
<PAGE> 17
17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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, budgeted, anticipate, expect, believes, goals or
projects and similar expressions are intended to identify forward-looking
statements. In accordance with the provisions of the Private Securities
Litigation Reform Act of 1995, the Company cautions that important factors could
cause actual results to differ materially from those in the forward-looking
statements. Such factors include the Company's substantial concentration of
operations in Venezuela, the political and economic risks associated with
international operations, the anticipated future development costs for the
Company's undeveloped proved reserves, the risk that actual results may vary
considerably from reserve estimates, the dependence upon the abilities and
continued participation of certain key employees of the Company, the risks
normally incident to the operation and development of oil and gas properties and
the drilling of oil and gas wells, the price for oil and natural gas, and other
risks indicated in filings with the Securities and Exchange Commission. The
following factors, among others, in some cases have affected and could cause
actual results and plans for future periods to differ materially from those
expressed or implied in any such forward-looking statements: fluctuations in oil
and gas prices, changes in operating costs, overall economic conditions,
political stability, acts of terrorism, currency and exchange risks, changes in
existing or potential tariffs, duties or quotas, availability of additional
exploration and development opportunities, availability of sufficient financing,
changes in weather conditions, and ability to hire, retain and train management
and personnel.
GENERAL
PRINCIPLES OF CONSOLIDATION AND ACCOUNTING METHODS
The consolidated financial statements include the accounts of the Company and
its subsidiaries. The Company's investment in GEOILBENT, its Russian joint
venture, is accounted for using proportionate consolidation based on the
Company's ownership interest. The Company's investment in Severneftegaz, a
Russian open joint stock company, is accounted for using the equity method
because of the significant influence the Company exercises over its operations
and management. All intercompany profits, transactions and balances have been
eliminated. The Company accounts for its investment in GEOILBENT and
Severneftegaz based on a fiscal year ending September 30.
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all acquisition, exploration,
and development costs incurred. The Company accounts for its oil and gas
properties using cost centers on a country by country basis. Proceeds from sales
of oil and gas properties are credited to the full-cost pools. Capitalized costs
of oil and gas properties are amortized within the cost centers on an overall
unit-of-production method using proved oil and gas reserves as determined by
independent petroleum engineers. Costs amortized include all capitalized costs
(less accumulated amortization), the estimated future expenditures (based on
current costs) to be incurred in developing proved reserves, and estimated
dismantlement, restoration and abandonment costs. (See Note 1 of Notes to
Consolidated Financial Statements.)
The following discussion of the Company's results of operations for the three
months ended March 31, 1999 and 1998 and financial condition at March 31, 1999
and December 31, 1998 should be read in conjunction with the Company's
Consolidated Financial Statements and related notes thereto included in PART I,
Item 1, "Financial Statements."
RESULTS OF OPERATIONS
The Company's results of operations for the three months ended March 31, 1999,
reflected the results for Benton-Vinccler, C.A. in Venezuela, which accounted
for more than 85% of the Company's production and oil sales revenue. As a result
of declines in world crude oil prices and lower production from the South
Monagas Unit due to lower capital spending and continuing operational problems
with certain high volume wells, oil sales in Venezuela were 40% lower in the
first three months of 1999 compared to 1998 with a 17% decrease in realized fees
per barrel (from $7.26 in 1998 to $6.05 in 1999) and a 27% decrease in oil sales
quantities (from 3,645,593 Bbls of oil in 1998 to 2,659,085 Bbls of oil in
1999). Benton-Vinccler also experienced increased operating expenses on a per
barrel basis primarily related to workovers and plant repairs and maintenance
which, especially when combined with the decreased fee
<PAGE> 18
18
realizations, represented a significantly higher percentage of oil sales
revenues during the period than in the prior period.
The following table presents selected expense items from the Company's
consolidated income statement items as a percentage of oil and gas sales:
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
-----------------------------------
1999 1998
------------- -------------
<S> <C> <C>
Lease Operating Costs and Production Taxes 61.9% 46.5%
Depletion, Depreciation and Amortization 29.9 38.8
General and Administrative 31.0 19.0
Interest 43.6 28.3
</TABLE>
THREE MONTHS ENDED MARCH 31, 1999 AND 1998
The Company had revenues of $22.0 million for the three months ended March 31,
1999. Expenses incurred during the period consisted of lease operating costs and
production taxes of $11.1 million, depletion, depreciation and amortization
expense of $5.4 million, general and administrative expense of $5.6 million,
interest expense of $7.8 million, income tax expense of $0.6 million and a
minority interest of $0.2 million. Net loss was $8.7 million or $0.29 per share
(diluted).
By comparison, the Company had revenues of $33.3 million for the three months
ended March 31, 1998. Expenses incurred during the period consisted of lease
operating costs and production taxes of $13.2 million, depletion, depreciation
and amortization expense of $11.1 million, write down of oil and gas properties
of $17.5 million, general and administrative expense of $5.4 million, interest
expense of $8.1 million, income tax benefit of $0.7 million and a minority
interest reduction of $0.4 million. Net loss for the period was $21.0 million or
$0.71 per share (diluted).
Revenues decreased $11.3 million, or 34%, during the three months ended March
31, 1999 compared to the corresponding period of 1998 primarily due to decreased
oil sales revenue in Venezuela as a result of declines in world crude oil prices
and lower sales quantities. Sales quantities for the three months ended March
31, 1999 from Venezuela and Russia were 2,659,085 Bbls and 333,102 Bbls,
respectively, compared to 3,645,593 Bbls and 127,402 Bbls, respectively, for the
three months ended March 31, 1998. Prices for crude oil averaged $6.05 per Bbl
(pursuant to terms of an operating service agreement) from Venezuela and $5.65
per Bbl from Russia for the three months ended March 31, 1999 compared to $7.26
per Bbl from Venezuela and $11.61 per Bbl from Russia for the corresponding
period of 1998. Investment earnings decreased $1.5 million, or 36%, during the
three months ended March 31, 1999 compared to the three months ended March 31,
1998 due to lower average cash and marketable securities balances. Revenues for
the three months ended March 31, 1999 were increased by a foreign exchange gain
of $1.4 million compared to a gain of $0.6 million during the corresponding
period of 1998.
Lease operating costs and production taxes decreased $2.1 million, or 16%,
during the three months ended March 31, 1999 compared to the three months ended
March 31, 1998 primarily due to reduced oil production in Venezuela. Depletion,
depreciation and amortization decreased $5.7 million, or 51%, during the three
months ended March 31, 1999 compared to the corresponding period of 1998
primarily due to reduced oil sales and write-downs of oil and gas properties in
Venezuela and Russia during 1998. Depletion expense per barrel of oil equivalent
produced from Venezuela and Russia during the three months ended March 31, 1999
was $1.57 and $2.10, respectively, compared to $2.83 and $3.67, respectively,
during the corresponding period of the previous year. As a result of the effect
of declines in world crude oil prices, at March 31, 1998 the Company recognized
a write-down of oil and gas properties in the Venezuela cost center of $17.5
million pursuant to the ceiling limitation prescribed by the full cost method of
accounting. General and administrative expenses increased $0.2 million, or 4%,
during three months ended March 31, 1999 compared to the corresponding period of
1998 primarily due to the costs of advisory services provided by J.P. Morgan
Securities, Inc. and costs incurred in the Company's Delta Centro and China
operations offset by decreased Venezuelan municipal taxes (which are a function
of oil revenues). Interest expense decreased $0.3 million, or 4%, during the
three months ended March 31, 1999 compared to the three months ended March 31,
1998 primarily due to the capitalization of interest expense. The Company
recognized a loss before income taxes and minority interest of $7.9 million
during the three months ended March 31, 1999 as compared to a loss of $22.0
million in the corresponding period of 1998, which resulted in increased income
tax expense of $1.3 million, or 186%. The loss attributable to the minority
interest decreased $0.6 million, or 150%, for the three months ended March 31,
1999 compared to the three months ended March 31, 1998 because the losses
attributable to the minority shareholders of Benton-Vinccler exceeded their
interest in equity capital and have therefore been included in the consolidated
net loss of the Company.
<PAGE> 19
19
DOMESTIC OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy Company, LLC
("Molino Energy"), which held 100% of these leases. The project area covers the
Molino, Gaviota and Caliente Fields, located approximately 35 miles west of
Santa Barbara, California. In consideration of the 40% participation interest in
the leases, the Company became the operator of the project and paid 100% of the
first $3.7 million and 53% of the remainder of the costs of the first well
drilled on the block. During 1998, the 2199 #7 exploratory well was drilled to
the Gaviota anticline. Drill stem tests proved to be inconclusive or
non-commercial, and the well was temporarily abandoned for further evaluation.
The Company's share of the drilling and testing of the 2199 #7 well was $8.5
million. In November 1998, the Company entered into an agreement to acquire
Molino Energy's interest in the leases in exchange for the release of its joint
interest billing obligations of approximately $1.9 million. The agreement to
acquire Molino Energy's interest will be finalized upon the completion of
certain lot splits and the assignment of various permits and rights.
INTERNATIONAL OPERATIONS
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%. However, Benton-Vinccler reported significantly lower effective tax
rates for 1996 and 1998 due to the effect of the devaluation of the Bolivar
while Benton-Vinccler uses the U.S. dollar as its functional currency, and
further in 1998 due to a deferred tax asset valuation allowance. The Company
cannot predict the timing or impact of future devaluations in Venezuela.
A 3-D seismic survey has been conducted over the southwestern portion of the
Delta Centro Block in Venezuela at a total cost to the Company of $6.9 million.
During the first quarter of 1999, drilling commenced on the Jarina-1 X, the
first of the block's exploration wells, with a total anticipated cost to the
Company of approximately $6-7 million. The well, which had a planned total depth
of 15,600 feet and was one of several structures identified from the new 3-D
seismic data, penetrated a thick potential reservoir sequence, but encountered
no hydrocarbons. The Company and its partners continue to evaluate the remaining
leads on the block, including their potential reserves and risk factors. The
Company's operations related to Delta Centro will be subject to oil and gas
industry taxation, which currently provides for royalties of 16.66% and income
taxes of 67.7%. As of March 31, 1999, the Company had incurred $11.9 million
related to the Delta Centro Block.
GEOILBENT is subject to a statutory income tax rate of 35%. GEOILBENT has also
been subject to various other tax burdens, including an oil export tariff which
was terminated effective July 1, 1996. Excise, pipeline and other taxes
(including a new oil export tariff introduced in 1999) continue to be levied on
all oil producers and certain exporters. The Russian regulatory environment
continues to be volatile and the Company is unable to predict the impact of
taxes, duties and other burdens for the future.
In December 1996, the Company acquired Benton Offshore China Company, a
privately held company headquartered in Denver, Colorado. Benton Offshore China
Company's principal asset is a petroleum contract with China National Offshore
Oil Corporation ("CNOOC") for an area known as Wan'An Bei, WAB-21. The WAB-21
petroleum contract covers 6.2 million acres in the South China Sea, with an
option for another one 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 also executed an agreement
on a portion of the same offshore acreage with Conoco Inc. The territorial
dispute has existed for many years, and there has been limited exploration and
no development activity in the area under dispute. It is uncertain when or how
this dispute will be resolved, and under what terms the various countries and
parties to the agreements may participate in the resolution, although certain
proposed economic solutions currently under discussion would result in the
Company's interest being reduced. Benton Offshore China Company has submitted
plans and budgets to CNOOC for an initial seismic program to survey the area.
However, exploration activities will be subject to resolution of such
territorial dispute. The Company has recorded no proved reserves attributable to
this petroleum contract.
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's National Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which has been extended to
May 2000. If the Company ultimately elects to continue through phases two and
three, it would be obligated to spend an additional $18 million over the
succeeding six years.
<PAGE> 20
20
In October 1997, the Company signed a farmout agreement with Shell Exploration
(China) Limited ("Shell") whereby the Company acquired a 50% participation
interest in Shell's Liaohe area onshore exploration project in northeast China.
Shell holds a petroleum contract with China National Petroleum Corporation to
explore and develop the deep rights in the Qingshui Block, a 563 square
kilometer area (approximately 140,000 acres) in the delta of the Liaohe River.
Shell is the operator of the project. In July 1998, the Company paid to Shell
50% of Shell's prior investment in the Block, which was approximately $4 million
($2 million to the Company). The Company is required to pay 100% of the first $8
million of the costs for the phase one exploration period, after which any
development costs will be shared equally. If a commercial well results from
phase one and the Company elects to continue to phase two, then the Company will
pay 100% of the first $8 million of the costs of the second phase of the
exploration period, after which any development costs will be shared equally. If
a commercial well does not result from phase one and the Company elects to
continue to phase two, then the Company and Shell will share costs equally. The
Company and Shell will share costs equally for the third exploration phase, if
any. During the first quarter of 1999, drilling commenced on the Qing-22 Deep
well as a part of the phase one exploration period activities.
In December 1997, the Company signed a memorandum of understanding with Petrosen
to receive a minimum 45% working interest in and to operate the approximately
one-million acre onshore Thies Block in western Senegal. In addition, the
Company obtained exclusive rights from Petrosen to evaluate and reprocess
geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea Bissau border in the south. The Company may
also choose certain blocks for further data acquisition and exploration
drilling. The Company's working interest in any offshore discovery will be 85%
with the remainder held by Petrosen. The Company's $5.4 million work commitment
on the Thies Block, where Petrosen has recently drilled and completed the
Gadiaga #2 discovery well, consists of hooking up the existing well, drilling
two additional wells and constructing a 41-kilometer (approximately 25-mile) gas
pipeline to Senegal's main electric generating facility near Dakar. The
Company's minimum commitment related to the offshore blocks involves seismic
reprocessing to be followed by additional data acquisition and drilling at the
Company's discretion.
In April 1998, the Company signed an agreement to earn a 40% equity interest in
Severneftegaz. Severneftegaz owns the exclusive rights to evaluate, develop and
produce the natural gas, condensate, and oil reserves in the Samburg and
Yevo-Yakha license blocks in West Siberia. The two blocks comprise 837,000 acres
within and adjacent to the Urengoy Field, Russia's largest producing natural gas
field. Pursuant to a Cooperation Agreement between the Company and
Severneftegaz, the Company will earn a 40% equity interest in exchange for
providing the initial capital needed to achieve natural gas production. The
Company's capital commitment will be in the form of providing or arranging a
$100 million credit facility for the project, the terms of which have yet to be
finalized, which is expected to be disbursed over the initial two-year
development phase. The Company has received voting shares representing a 40%
ownership in Severneftegaz that contain restrictions on their sale and transfer.
A Share Disposition Agreement provides for removal of the restrictions as
disbursements are made under the credit facility. As of March 31, 1999, the
Company had loaned $10.1 million to Severneftegaz pursuant to an interim credit
facility, with interest at LIBOR plus 3%, and had earned the right to remove
restrictions from shares representing an approximate 2.8% equity interest. In
December 1998 and January 1999, the Company purchased shares representing an
additional 15% equity interest not subject to any sale or transfer restrictions.
The Company owned a total of 55% of voting shares of Severneftegaz as of March
31, 1999, of which 17.8% was not subject to any restrictions. Due to the
significant influence it exercises over the operating and financial policies of
Severneftegaz, the Company has accounted for its interest in Severneftegaz using
the equity method. Certain provisions of Russian corporate law would effectively
require minority shareholder consent in the making of new agreements between the
Company and Severneftegaz, or to the changing of any terms in any existing
agreements between the two partners such as the Cooperation Agreement and the
Share Disposition Agreement, including the conditions upon which the
restrictions on the shares could be removed.
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION
The Company's results of operations and cash flow are affected by changing oil
and gas prices. However, the Company's Venezuelan revenues are based on a fee
adjusted quarterly by the percentage change of a basket of crude oil prices
instead of by absolute dollar changes, which dampens both any upward and
downward effects of changing prices on the Company's Venezuelan revenues and
cash flows. If the price of oil and gas increases, there could be an increase in
the cost to the Company for drilling and related services because of increased
demand, as well as an increase in revenues. Fluctuations in oil and gas prices
may affect the Company's total planned development activities and capital
expenditure program.
There are presently no restrictions in either Venezuela or Russia that restrict
converting U.S. dollars into local currency. However, from June 1994 through
April 1996, Venezuela implemented exchange controls which significantly limited
the ability to convert local currency into U.S. dollars. Because payments made
to Benton-Vinccler are made in U.S. dollars into its United States bank account,
and Benton-Vinccler is not subject to regulations requiring the conversion or
<PAGE> 21
21
repatriation of those dollars back into Venezuela, the exchange controls did not
have a material adverse effect on Benton-Vinccler or the Company. Currently,
there are no exchange controls in Venezuela or Russia that restrict conversion
of local currency into U.S. dollars.
Within the United States, inflation has had a minimal effect on the Company, but
it is potentially an important factor in results of operations in Venezuela and
Russia. With respect to Benton-Vinccler and GEOILBENT, substantially all of the
sources of funds, including the proceeds from oil sales, the Company's
contributions and credit financings, are denominated in U.S. dollars, while
local transactions in Russia and Venezuela are conducted in local currency. When
the rate of increase in the value of the dollar compared to the Venezuelan
bolivar or the Russian ruble is less than the rate of inflation in these
countries, then inflation could be expected to have an adverse effect on the
Company.
During the three months ended March 31, 1999, the Company realized net foreign
exchange gains, primarily as a result of the decline in the value of the
Venezuelan bolivar and the Russian ruble during periods when the Company's
Venezuela-related subsidiaries and GEOILBENT had substantial net monetary
liabilities denominated in bolivares and rubles. During the three months ended
March 31, 1999, the Company's net foreign exchange gains attributable to its
Venezuelan and Russian operations were $0.3 million and $1.0 million,
respectively. However, there are many factors affecting foreign exchange rates
and resulting exchange gains and losses, many of which are beyond the control of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the U.S. dollar. It is not possible to predict the extent
to which the Company may be affected by future changes in exchange rates and
exchange controls.
The Company's operations are affected by political developments and laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and results.
CAPITAL RESOURCES AND LIQUIDITY
The oil and gas industry is a highly capital intensive business. The Company
requires capital principally to fund the following costs: (i) drilling and
completion costs of wells and the cost of production and transportation
facilities; (ii) geological, geophysical and seismic costs; and (iii)
acquisition of interests in oil and gas properties. The amount of available
capital will affect the scope of the Company's operations and the rate of its
growth.
The net funds raised and/or used in each of the operating, investing and
financing activities for the three months ended March 31 are summarized in the
following table and discussed in further detail below (in thousands):
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
-----------------------------------
1999 1998
------------- ----------
<S> <C> <C>
Net cash provided by operating activities $ 6,290 $ 21,478
Net cash used in investing activities (11,245) (13,507)
Net cash provided by (used in) financing activities (770) 3,811
============ ==========
Net increase (decrease) in cash $ (5,725) $ 11,782
============ ==========
</TABLE>
At March 31, 1999, the Company had current assets of $73.3 million and current
liabilities of $43.5 million resulting in working capital of $29.8 million and a
current ratio of 1.7:1. This compares to the Company's working capital of $55.9
million and a current ratio of 2.5:1 at December 31, 1998. The decrease of $26.1
million was due primarily to (i) expenditures related to exploration and
development in Venezuela, Russia and China and (ii) lower oil sales as a result
of declines in world crude oil prices and oil sales quantities.
CASH FLOW FROM OPERATING ACTIVITIES. During the three months ended March 31,
1999 and 1998, net cash provided by operating activities was approximately $6.3
million and $21.5 million, respectively. Cash flow from operating activities
decreased by $15.2 million during the three months ended March 31, 1999 compared
to the corresponding period of the prior year due primarily to the collection of
accrued oil revenues substantially offset by reduced revenues, increased lease
operating costs and interest expense.
CASH FLOW FROM INVESTING ACTIVITIES. During the three months ended March 31,
1999 and 1998, the Company had drilling and production related capital
expenditures of approximately $15.9 million and $39.3 million, respectively. Of
the 1999 expenditures, $7.0 million was attributable to the development of the
South Monagas Unit in Venezuela, $0.5 million
<PAGE> 22
22
related to the development of the North Gubkinskoye Field in Russia, $3.6
million related to a 3-D seismic survey and exploratory well costs in the Delta
Centro Block in Venezuela, $4.0 million related to the development of the
Qingshui Block in China, and $0.8 was attributable to other projects. The
capital expenditures during the three months ended March 31, 1999 and 1998 were
substantially offset by net redemptions of marketable securities of $11.4
million and $25.9 million, respectively.
During 1998, the Company instituted a capital expenditure program which
minimized expenditures to those that the Company believed were necessary in
order to maintain current producing properties. This policy was instituted in
response to the low market price for oil. The Company expects to continue
limiting capital expenditures at this maintenance level until such time as cash
flow from operating, investing and/or financing activities permit resumption of
exploration and development programs on a broader scale.
The Company expects 1999 capital expenditures of $35-45 million, including $7-8
million in expenditures by GEOILBENT in Russia, net to the Company's interest
(which are expected to be funded from borrowings under the EBRD Credit Facility,
cash flow from operations or other financings). Additionally, the Company
anticipates providing or arranging loans of up to $100 million over the next two
years to Severneftegaz pursuant to an equity acquisition agreement signed in
April 1998. The Company is currently evaluating funding alternatives for the
loans to Severneftegaz. The Company's indentures contain provisions that
restrict the manner in which the Company can invest in certain of its current
operations including GEOILBENT.
The Company continually assesses its 1999 capital expenditure program in view of
its financial resources and of industry and commodity price changes. Its total
1999 capital expenditure requirements include approximately $10-15 million at
South Monagas Unit, $10-12 million for well commitments in China and at Delta
Centro, and $7-10 million for Severneftegaz. The Company anticipates that
Geoilbent will continue to fund itself through its own cash flows and credit
facilities. The Company's remaining capital commitments worldwide are relatively
minimal and for the most part are substantially at the Company's discretion. The
timing and size of the 1999 investments for Severneftegaz are also substantially
under the Company's discretion. The Company believes it has or can obtain
sufficient funding for certain of its expected capital requirements from working
capital and cash flow from operations.
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond the Company's control.
If oil prices continue at or near current levels, and if oil production
continues at expected levels, the Company believes that its current cash and
cash provided by operating activities will be sufficient to meet the Company's
liquidity needs for routine operations and to service its outstanding debt
through 1999. If oil prices and production volumes later in 1999 and early in
2000 result in cash flows that are less than currently planned, then the Company
may have to reduce further its planned capital and operating expenditures in
2000, which could have negative effects on future oil production rates. The
Company continues to evaluate and review strategic alternatives and has engaged
J.P. Morgan Securities, Inc. to advise the Company related to these
alternatives. In the event that future cash requirements are greater than the
Company's financial resources, the Company intends to pursue strategic joint
ventures or alliances with other industry partners, sell property interests,
merge or combine with another entity, or issue debt or equity securities.
CASH FLOW FROM FINANCING ACTIVITIES. In May 1996, the Company issued $125
million in 11.625% senior unsecured notes due May 1, 2003. In November 1997, the
Company issued $115 million in 9.375% senior unsecured notes due November 1,
2007, of which the Company subsequently repurchased $10 million at their par
value. Interest on the notes is due May 1st and November 1st of each year. The
indenture agreements provide for certain limitations on liens, additional
indebtedness, certain investment and capital expenditures, dividends, mergers
and sales of assets. At March 31, 1999, the Company was in compliance with all
covenants of the indentures.
The EBRD and IMB have agreed to lend a total of $65 million to GEOILBENT (owned
34% by the Company) under parallel reserve-based, loan agreements. To date,
GEOILBENT has borrowed $28.8 million. The proceeds from the loans are being used
by GEOILBENT to develop the North Gubkinskoye and Prisklonovoye Fields in West
Siberia, Russia. Additional borrowings will be based on achieving certain
reserve and production milestones.
YEAR 2000 COMPLIANCE
The Year 2000 problem concerns the inability of information systems to properly
recognize and process date-sensitive information beyond January 1, 2000. The
Company began a process of assessing its information technology systems in
November 1997 and has to date not uncovered any significant Year 2000
deficiencies.
<PAGE> 23
23
Substantially all of the software utilized by the Company is purchased or
licensed from external providers. The Company's home office business systems are
Year 2000 compliant. Its subsidiaries are currently in the process of upgrading
their business systems, with completion anticipated during the second quarter of
1999 in Venezuela and the third quarter of 1999 in Russia. A review of the
Company's non-financial software and imbedded chip technology is currently
underway to assess the impact of the Year 2000 on systems such as plant flow
control devices, product measurement and delivery devices and fire or other
disaster-related safety systems. To date, the costs associated with required
modifications to become Year 2000 compliant have not exceeded $100,000, and the
Company does not anticipate that the cost of converting any non-compliant
systems will be material to its financial condition.
The Company anticipates the completion of the process of obtaining Year 2000
compliance information from its material suppliers and customers during the
second quarter of 1999. To the extent that the Company does not receive adequate
responses from its material third-party suppliers and customers, it is prepared
to develop contingency plans that would include changing suppliers and customers
to those who have demonstrated Year 2000 readiness. However, there can be no
assurance that the Company will be successful in finding such alternative
suppliers and customers. The oil produced in Venezuela by the Company, which is
delivered to PDVSA under the terms of an operating service agreement lasting
until 2012, represented approximately 91% of the Company's oil sales during 1998
and 90% for the three months ended March 31, 1999. In the event that PDVSA is
unable to accept deliveries of, or make payment for, the oil produced by the
Company due to a Year 2000 failure, the Company's operations and financial
position could be materially and adversely affected.
The failure to correct a material Year 2000 problem could result in an
interruption in, or a failure of, certain normal business activities or
operations. Such failures could materially and adversely affect the Company's
results of operations, liquidity and financial condition. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from the
uncertainty of the Year 2000 readiness of third-party suppliers and customers,
the Company is unable to determine at this time whether the consequences of Year
2000 failures will have a material impact on the Company's results of
operations, liquidity or financial condition.
<PAGE> 24
24
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.
ITEM 2. CHANGES IN SECURITIES
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None.
(b) Reports on Form 8-K
None.
<PAGE> 25
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.
BENTON OIL AND GAS COMPANY
Dated: May 12, 1999 By: /s/A.E. Benton
-------------------------------------
A.E. Benton
President and Chief Executive Officer
Dated: May 12, 1999 By: /s/James M. Whipkey
------------------------------------------------
James M. Whipkey
Senior Vice President and Chief Financial Officer
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10Q FOR
THE PERIOD ENDED MARCH 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<CASH> 12,422
<SECURITIES> 29,782
<RECEIVABLES> 18,198
<ALLOWANCES> 3,236
<INVENTORY> 0
<CURRENT-ASSETS> 73,307
<PP&E> 508,583
<DEPRECIATION> 344,560
<TOTAL-ASSETS> 336,050
<CURRENT-LIABILITIES> 43,480
<BONDS> 287,614
0
0
<COMMON> 296
<OTHER-SE> 4,030
<TOTAL-LIABILITY-AND-EQUITY> 336,050
<SALES> 17,971
<TOTAL-REVENUES> 22,040
<CGS> 16,498
<TOTAL-COSTS> 16,498
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7,843
<INCOME-PRETAX> (7,868)
<INCOME-TAX> 640
<INCOME-CONTINUING> (8,663)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (8,663)
<EPS-PRIMARY> (.29)
<EPS-DILUTED> (.29)
</TABLE>
