<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, 2000 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
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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
incorporation or organization) Identification Number)
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 11, 2000, 29,661,663 shares of the
Registrant's Common Stock were outstanding.
<PAGE> 2
2
<TABLE>
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
<CAPTION>
Page
----
<S> <C>
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets at March 31, 2000
and December 31, 1999 (Unaudited)..................................3
Consolidated Statements of Operations for the Three
Months Ended March 31, 2000 and 1999 (Unaudited)...................4
Consolidated Statements of Cash Flows for the Three
Months Ended March 31, 2000 and 1999 (Unaudited)...................5
Notes to Consolidated Financial Statements................................7
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS........................................19
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.................25
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS..........................................................26
Item 2. CHANGES IN SECURITIES......................................................26
Item 3. DEFAULTS UPON SENIOR SECURITIES............................................26
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........................26
Item 5. OTHER INFORMATION..........................................................26
Item 6. EXHIBITS AND REPORTS ON FORM 8-K...........................................26
SIGNATURES.....................................................................................27
</TABLE>
<PAGE> 3
3
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
<TABLE>
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, unaudited)
<CAPTION>
MARCH 31, DECEMBER 31,
2000 1999
--------- ------------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents $ 30,389 $ 21,147
Restricted cash 12 12
Marketable securities 2,529 4,469
Accounts and notes receivable:
Accrued oil and gas revenue 30,643 27,339
Joint interest and other, net 4,605 4,993
Prepaid expenses and other 1,835 1,635
--------- ---------
TOTAL CURRENT ASSETS 70,013 59,595
RESTRICTED CASH 46,545 46,449
OTHER ASSETS 9,767 10,569
DEFERRED INCOME TAXES 12,004 12,186
INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES 65,438 61,357
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of $16,299 and
$16,117 excluded from amortization in 2000 and 1999, respectively) 445,519 435,449
Furniture and fixtures 10,301 10,031
--------- ---------
455,820 445,480
Accumulated depletion, impairment and depreciation (363,091) (359,325)
--------- ---------
92,729 86,155
--------- ---------
$ 296,496 $ 276,311
========= =========
LIABILITIES AND STOCKHOLDERS' DEFICIT
- -------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other $ 4,997 $ 3,317
Accrued interest payable 10,766 4,686
Accrued expenses 20,791 17,105
Income taxes payable 6,291 2,392
Current portion of long term debt -- 2
--------- ---------
TOTAL CURRENT LIABILITIES 42,845 27,502
LONG TERM DEBT 264,575 264,575
COMMITMENTS AND CONTINGENCIES
MINORITY INTERESTS 3,046 1,412
STOCKHOLDERS' DEFICIT:
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 29,712 shares at March 31, 2000 and 29,627 shares at
December 31, 1999 297 296
Additional paid-in capital 147,290 147,078
Retained deficit (160,858) (163,853)
Treasury stock, at cost, 50 shares (699) (699)
--------- ---------
TOTAL STOCKHOLDERS' DEFICIT (13,970) (17,178)
--------- ---------
$ 296,496 $ 276,311
========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 4
4
<TABLE>
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data, unaudited)
<CAPTION>
THREE MONTHS ENDED MARCH 31,
----------------------------
2000 1999
-------- -------
<S> <C> <C>
REVENUES
Oil sales $31,433 $16,090
------- -------
31,433 16,090
------- -------
EXPENSES
Operating expenses 9,418 10,140
Depletion, depreciation and amortization 3,770 4,668
General and administrative 4,391 4,767
Taxes other than on income 1,068 662
------- -------
18,647 20,237
------- -------
INCOME (LOSS) FROM OPERATIONS 12,786 (4,147)
OTHER NON-OPERATING INCOME (EXPENSE)
Investment income and other 2,044 2,456
Interest expense (7,445) (7,482)
Net gain on exchange rates 153 388
------- -------
(5,248) (4,638)
------- -------
INCOME (LOSS) FROM CONSOLIDATED COMPANIES BEFORE
INCOME TAXES AND MINORITY INTERESTS 7,538 (8,785)
INCOME TAX EXPENSE 4,636 753
------- -------
INCOME (LOSS) BEFORE MINORITY INTERESTS 2,902 (9,538)
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY COMPANIES 1,634 155
------- -------
INCOME (LOSS) FROM CONSOLIDATED COMPANIES 1,268 (9,693)
EQUITY IN NET EARNINGS OF AFFILIATED COMPANIES 1,727 1,030
------- -------
NET INCOME (LOSS) $ 2,995 $(8,663)
======= =======
NET INCOME (LOSS) PER COMMON SHARE:
Basic $ 0.10 $ (0.29)
======= =======
Diluted $ 0.10 $ (0.29)
======= =======
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 5
5
<TABLE>
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands, unaudited)
<CAPTION>
THREE MONTHS ENDED MARCH 31,
----------------------------
2000 1999
-------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (loss) $ 2,995 $ (8,663)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depletion, depreciation and amortization 3,770 4,668
Amortization of financing costs 349 349
Loss on disposal of assets -- 38
Equity in earnings of affiliated companies (1,727) (1,030)
Allowance for employee notes 82 --
Minority interest in undistributed earnings of subsidiary 1,634 155
Deferred income taxes 182 --
Changes in operating assets and liabilities:
Accounts receivable (2,998) 2,012
Prepaid expenses and other (200) (110)
Accounts payable 1,680 (872)
Accrued interest payable 6,080 6,033
Accrued expenses 3,686 1,819
Income taxes payable 3,899 499
-------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 19,432 4,898
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions of property and equipment (10,344) (15,006)
Investment in and advances to affiliated company (2,354) (7,071)
Increase in restricted cash (96) (128)
Purchase of marketable securities (60) (8,525)
Maturities of marketable securities 2,000 19,917
-------- --------
NET CASH USED IN INVESTING ACTIVITIES (10,854) (10,813)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from exercise of stock options and warrants 213 --
Payments on short term borrowings and notes payable (2) (3)
(Increase) decrease in other assets 453 (92)
-------- --------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 664 (95)
-------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 9,242 (6,010)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 21,147 17,198
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 30,389 $ 11,188
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for interest expense $ 1,087 $ 1,461
======== ========
Cash paid during the period for income taxes $ 745 $ 846
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 6
6
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
During the three months ended March 31, 2000, the Company recorded an allowance
for doubtful accounts in the amount of $0.1 million related to accrued interest
on amounts owed to the Company by its former Chief Executive Officer (see Note
12).
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, 2000 (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 principally in Venezuela and Russia.
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 the Company has significant influence.
All intercompany profits, transactions and balances have been eliminated. The
Company accounts for its investment in Geoilbent, Ltd. ("Geoilbent") and Arctic
Gas Company ("Arctic Gas"), formerly Severneftegaz, based on a fiscal year
ending September 30 (see Note 2).
In January 2000, in connection with the release of Emerging Issues Task Force
(EITF) Issues Summary 00-01, "Applicability of the Pro Rata Method of
Consolidation to Investments in Certain Partnerships and Other Unincorporated
Joint Ventures", the Company reviewed the accounting for its investment in
Geoilbent under the proportionate consolidation method. As a result of this
review, the Company decided to report its investment in Geoilbent using the
equity method. This change had no effect on net income or the Company's
proportionate share of oil and gas reserves. It did, however, result in the
reduction of the Company's reported consolidated net cash flows for the three
months ended March 31, 1999 of $1.8 million. For the three months ended March
31, 1999, revenues were reduced by the Company's proportionate share, which was
$1.9 million, expenses were reduced $3.4 million and net other non-operating
expenses were increased by $1.5 million. Summarized financial information for
Geoilbent is included in Note 7.
As a result of the decline in oil prices, the Company instituted in 1998, and
continued in 1999, a capital expenditure program to reduce expenditures to those
that the Company believed were necessary to maintain current producing
properties. In the second half of 1999, oil prices recovered substantially, and
the Company concluded a project to assess its strategic alternatives. In
December 1999, the Company entered into incentive-based development alliance
agreements with Schlumberger and Helmerich & Payne as part of its plans to
resume development of the South Monagas Unit in Venezuela (see Note 8).
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production, oil production quantities
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 2000. However, the
Company has a planned capital expenditure program that will require, in addition
to its working capital and cash flow from operations, short-term borrowings for
working capital purposes. If the Company's future cash requirements are greater
than its financial resources, the Company intends to pursue one or more of the
following alternatives: reduce its capital expenditure programs, substantially
all of which are within its discretion; reduce its operating and administrative
expenditures; form strategic joint ventures or alliances with other industry
partners; sell property interest; merge or combine with another entity; or issue
debt or equity securities. There can be no assurance that any of the
alternatives will be available on terms acceptable to the Company.
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,
2000, and the results of operations and cash flows for the three month periods
ended March 31, 2000 and 1999. 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, 1999 for additional disclosures, including a summary of the
Company's accounting policies.
The results of operations for the three month period ended March 31, 2000 are
not necessarily indicative of the results to be expected for the full year.
<PAGE> 8
8
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
Allowance for doubtful accounts related to employee notes was $5.9 million at
March 31, 2000 and December 31, 1999 (see Note 12). Allowance for doubtful
accounts related to joint interest and other accounts receivable was $0.3
million at March 31, 2000 and December 31, 1999.
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 months 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 ended March 31, 1999 attributable to the
minority shareholders has been included in the consolidated net loss of the
Company. No such adjustment was necessary for the three months ended March 31,
2000.
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 $2.5 million in commercial paper at March
31, 2000 and $4.5 million in commercial paper at December 31, 1999.
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. The Company
did not have any items of other comprehensive income during the three months
ended March 31, 2000 or March 31, 1999 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 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>
INCOME/ AMOUNT
(LOSS) SHARES PER SHARE
-------- ------ ---------
<S> <C> <C> <C>
FOR THE THREE MONTHS ENDED MARCH 31, 2000
- -----------------------------------------
BASIC EPS
Income attributable to common stockholders $ 2,995 29,589 $ 0.10
======= ====== ======
Effect of Dilutive Securities:
Stock options and warrants -- 108 --
------- ------- ------
DILUTED EPS
Income attributable to common stockholders $ 2,995 29,697 $ 0.10
======= ====== ======
FOR THE THREE MONTHS ENDED MARCH 31, 1999
- -----------------------------------------
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)
======= ====== ======
</TABLE>
An aggregate 5.8 million and 5.9 million options and warrants were excluded from
the earnings per share calculations because they were anti-dilutive for the
three months ended March 31, 2000 and 1999, respectively.
<PAGE> 9
9
PROPERTY AND EQUIPMENT
The Company follows 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 gas reserves are capitalized as incurred, including
exploration overhead of $0.4 million and $0.6 million for the three months ended
March 31, 2000 and 1999, respectively, and capitalized interest of $0.1 million
and $0.4 million for the three months ended March, 2000 and 1999, respectively.
Only overhead that is directly identified with acquisition, exploration or
development activities is capitalized. All costs related to production, general
corporate overhead and similar activities are expensed as incurred.
The costs of unproved properties are excluded from amortization until the
properties are evaluated. Excluded costs attributable to the China and other
cost centers were $16.3 million and $16.1 million, at March 31, 2000 and
December 31, 1999, respectively. The Company regularly evaluates its unproved
properties on a country by country basis for possible impairment. If the Company
abandons 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 principal portion of excluded costs, except those related to the
acquisition of Benton Offshore China Company, is expected to be included in
amortizable costs during the next two to three years. 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, which was all
attributable to the Venezuelan cost center, for the three months ended March 31,
2000 and 1999 was $3.3 million and $4.2 million ($1.48 and $1.57 per equivalent
barrel), respectively. Depreciation of furniture and fixtures is computed using
the straight-line method with depreciation rates based upon the estimated useful
life of the property, generally 5 years. Leasehold improvements are depreciated
over the life of the applicable lease. Depreciation expense was $0.4 million for
the three months ended March 31, 2000 and 1999.
RESTRUCTURING
In an effort to reduce general and administrative expenses, the Company reduced
its administrative and technical staff in Carpinteria by 10 persons in October
1999. In connection with the reduction in staff, the Company recorded
termination benefits expenses in October 1999 of $0.8 million that are payable
from October 1999 through September 2000. The unpaid portion of these benefits
of $0.1 million is included in Accrued Expenses at March 31, 2000.
RECLASSIFICATIONS
Certain items in 1999 have been reclassified to conform to the 2000 financial
statement presentation.
NOTE 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES
Investments in Geoilbent and Arctic Gas are accounted for using the equity
method due to the significant influence the Company exercises over their
operations and management. Investments include amounts paid to the investee
companies for shares of stock or joint venture interests and other costs
incurred associated with the acquisition and evaluation of technical data for
the oil and gas fields operated by the investee companies. Other investment
costs are amortized using the units of production method based on total proved
reserves of the investee companies. Equity in earnings of Geoilbent and Arctic
Gas are based on a fiscal year ending September 30. No dividends have been paid
to the Company from Geoilbent or Arctic Gas.
Equity in earnings and losses and investments in and advances to companies
accounted for using the equity method are as follows (in thousands):
<TABLE>
<CAPTION>
GEOILBENT, LTD. ARCTIC GAS COMPANY TOTAL
-------------------- -------------------- -------------------
MAR 31, DEC 31, MAR 31, DEC 31, MAR 31, DEC 31,
2000 1999 2000 1999 2000 1999
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Investments
In equity in net assets $28,056 $28,056 $(2,142) $(2,419) $25,914 $25,637
Other costs, net of amortization (510) (542) 17,108 17,128 16,598 16,586
------- ------- ------- ------- ------- -------
Total investments 27,546 27,514 14,966 14,709 42,512 42,223
Advances -- -- 15,436 13,364 15,436 13,364
Equity in earnings (losses) 8,091 6,167 (601) (397) 7,490 5,770
------- ------- ------- ------- ------- -------
Total $35,637 $33,681 $29,801 $27,676 $65,438 $61,357
======= ======= ======= ======= ======= =======
</TABLE>
<PAGE> 10
10
NOTE 3 - LONG TERM DEBT
Long term debt consists of the following (in thousands):
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
2000 1999
--------- ------------
<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 34,575 34,575
Other -- 2
-------- --------
264,575 264,577
Less current portion -- 2
-------- --------
$264,575 $264,575
======== ========
</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, 2000, 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 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.
NOTE 4 - 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 commenced on May 1,
2000 which is expected to last approximately two months. 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. 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. As a result of expenditures
made related to the exploration work program, the letter of credit has been
reduced to $7.7 million.
<PAGE> 11
11
In November 1997, the Company entered into an agreement with Morgan Guaranty
which provided for a $1 million cash collateralized 2-year letter of credit,
which has been extended to November 2000, to secure its obligations under the
first exploration phase of a Production Sharing Agreement ("PSA") with Jordan's
Natural Resources Authority ("NRA"). The Company has not completed its
obligations under the first exploration phase of the agreement and does not
expect that the PSA will be extended beyond its May 17, 2000 expiration date. As
a result, the Company expects to record a liability to the NRA for the
obligation remaining under the PSA, resulting in impairment expense of
approximately $1 million, during the second quarter of 2000.
The Company has employment contracts with three 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 December 31, 2000
to February 28, 2003. The Company has also entered into employment agreements
with five 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 (see
Notes 8 and 11). 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 (see Note 7).
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 5 - TAXES
TAXES OTHER THAN ON INCOME
The Company pays a municipal tax of approximately 2.75% on operating fee
revenues it receives for production from the South Monagas Unit. The Company has
incurred the following Venezuelan municipal taxes and other taxes (in
thousands):
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
2000 1999
--------- --------
<S> <C> <C>
Venezuelan Municipal Taxes $ 818 $419
Franchise Taxes 40 42
Payroll and Other Taxes 210 201
------ ----
$1,068 $662
====== ====
</TABLE>
TAXES ON INCOME
At December 31, 1999, the Company had, for federal income tax purposes,
operating loss carryforwards of approximately $100 million expiring in the years
2003 through 2019. 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, 2000, the Company recorded deferred tax
assets generated from current period operating losses and a valuation allowance
of $1.3 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.
<PAGE> 12
12
NOTE 6 - OPERATING SEGMENTS
The Company regularly allocates resources to and assesses the performance of its
operations by segments that are organized by unique geographic and operating
characteristics. The segments are organized in order to manage regional
business, currency and tax related risks and opportunities. Revenues from the
Venezuela operating segment are derived primarily from the production and sale
of oil. 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.
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
----------------------------
2000 1999
--------- ---------
<S> <C> <C>
OPERATING SEGMENT REVENUES
Oil sales
Venezuela $ 31,433 $ 16,090
--------- --------
Total oil sales 31,433 16,090
--------- --------
OPERATING SEGMENT INCOME (LOSS)
Venezuela $ 6,747 $ (3,861)
Russia 1,301 885
United States and other (5,053) (5,687)
--------- --------
Net income (loss) $ 2,995 $ (8,663)
========= ========
<CAPTION>
MARCH 31, DECEMBER 31,
2000 1999
--------- ---------
OPERATING SEGMENT ASSETS
Venezuela $ 147,360 $124,942
Russia 66,132 61,989
United States and other 186,808 188,000
--------- --------
Sub-total 400,300 374,931
Intersegment eliminations (103,804) (98,620)
--------- --------
Total assets $ 296,496 $276,311
========= ========
</TABLE>
<PAGE> 13
13
NOTE 7 - RUSSIAN OPERATIONS
GEOILBENT, LTD.
The Company owns 34% of Geoilbent, Ltd., a Russian limited liability company
formed in 1991 to develop, produce and market crude oil from the North
Gubkinskoye Field in the West Siberia region of Russia. The Company's investment
in Geoilbent is accounted for using the equity method. Sales quantities
attributable to Geoilbent for the three months ended December 31, 1999 and 1998
were 1,197,604 barrels and 333,102 barrels, respectively. Prices for crude oil
for the three months ended December 31, 1999 and 1998 averaged $14.55 and $5.65
per barrel, respectively. Depletion expense attributable to Geoilbent for the
three months ended December 31, 1999 and 1998 was $2.14 and $2.10 per barrel,
respectively. Summarized financial information for Geoilbent follows (in
thousands). All amounts represent 100% of Geoilbent.
<TABLE>
<CAPTION>
THREE MONTHS ENDED DECEMBER 31,
-------------------------------
1999 1998
-------- -------
<S> <C> <C>
Revenues
Oil sales $ 17,421 $ 5,532
-------- -------
17,421 5,532
-------- -------
Expenses
Operating expenses 2,380 1,066
Depletion, depreciation and amortization 2,372 3,001
General and administrative 643 533
Taxes other than on income 2,275 1,723
-------- -------
7,670 6,323
-------- -------
Income (loss) from operations 9,751 (791)
Other Non-Operating Income (Expense)
Other income (expense) (236) 639
Interest expense (2,010) (1,062)
Net gain (loss) on exchange rates (393) 3,020
-------- -------
(2,639) 2,597
-------- -------
Income before income taxes 7,112 1,806
Income tax expense (benefit) 1,453 (331)
-------- -------
Net income $ 5,659 $ 2,137
======== =======
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1999 1999
------------ -------------
<S> <C> <C>
Current assets $ 30,081 $ 25,699
Other assets 139,672 139,488
Current liabilities 9,315 10,276
Other liabilities 54,121 54,254
Net equity 106,317 100,657
</TABLE>
The European Bank for Reconstruction and Development ("EBRD") and International
Moscow Bank ("IMB") together have agreed to lend up to $65 million to Geoilbent,
based on achieving certain reserve and production milestones, under parallel
reserve-based loan agreements. 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 on the semiannual interest payment dates beginning January 27, 2001
and ending by 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.
Geoilbent began borrowing under these facilities in October 1997 and has
<PAGE> 14
14
borrowed a total of $48.5 million through December 31, 1999. The proceeds from
the loans are being used by Geoilbent to develop the North Gubkinskoye and
Prisklonovoye Fields in West Siberia, Russia.
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, which are included in
accounts receivable. 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 until the first half of
2000.
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 was
subordinated to payments due to the EBRD and IMB and, accordingly, the credit
facility was reclassified from current to long term in 1998. The credit facility
contains no restrictive covenants and no financial ratio covenants. At December
31, 1999, $3.0 million was outstanding under the credit facility.
Excise, pipeline and other taxes, including an oil export tariff of 15 Euros per
ton ($1.97 per barrel) 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.
ARCTIC GAS COMPANY
In April 1998, the Company signed an agreement to earn a 40% equity interest in
Arctic Gas Company, formerly Severneftegaz. Arctic Gas owns the exclusive rights
to evaluate, develop and produce the natural gas, condensate, and oil reserves
in the Samburg and Yevo-Yakha license blocks in West Siberia. The two blocks
comprise 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 Arctic Gas, 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 and timing
of which have yet to be finalized. The Company has received voting shares
representing a 40% ownership in Arctic Gas that contain restrictions on their
sale and transfer. A Share Disposition Agreement provides for removal of the
restrictions as disbursements are made under the credit facility. As of March
31, 2000, the Company had loaned $15.4 million to Arctic Gas 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 6% equity
interest. In December 1998 and in 1999, the Company purchased shares
representing an additional 19% equity interest not subject to any sale or
transfer restrictions. The Company owned a total of 59% of the outstanding
voting shares of Arctic Gas as of March 31, 2000, of which 25% were not subject
to any restrictions.
Due to the significant influence it exercises over the operating and financial
policies of Arctic Gas, the Company has accounted for its interest in Arctic Gas
using the equity method. The Company's share in the equity losses of Arctic Gas
were $0.2 million for the three months ended December 31, 1999. The Company had
a weighted-average 25% and 16% equity interest not subject to any sale or
transfer restrictions for the three months ended March 31, 2000 and 1999,
respectively. Certain provisions of Russian corporate law would effectively
require minority shareholder consent to enter into new agreements between the
Company and Arctic Gas, or change 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.
<PAGE> 15
15
Summarized financial information for Arctic Gas Company follows (in thousands).
All amounts represent 100% of Arctic Gas Company.
<TABLE>
<CAPTION>
THREE MONTHS ENDED DECEMBER 31,
-------------------------------
1999 1998
----------- ----------
<S> <C> <C>
Expenses
Depreciation $ 22 $ 19
General and administrative 281 1,432
Taxes other than on income 15 12
-------- --------
318 1,463
-------- --------
Other Non-Operating Income (Expense)
Net gain (loss) on exchange rates (237) 66
Interest expense (226) (67)
-------- --------
(463) (1)
-------- --------
Loss before income taxes (781) (1,464)
Income tax expense -- --
-------- --------
Net loss $ (781) $ (1,464)
======== ========
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1999 1999
------------ -------------
<S> <C> <C>
Current assets $ 569 $ 1,513
Other assets 6,833 5,043
Current liabilities 18,259 18,068
Net deficit (10,857) (11,512)
</TABLE>
<PAGE> 16
16
NOTE 8 - 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 (the "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 August 1999, Benton-Vinccler sold its recently-constructed power generation
facility located in the Uracoa Field of the South Monagas Unit in Venezuela for
$15.1 million. Concurrently with the sale, Benton-Vinccler entered into a
long-term power purchase agreement with the purchaser of the facility to provide
for the electrical needs of the field throughout the remaining term of the
operating service agreement. The cost of electricity to be provided under terms
of the power purchase agreement approximate that previously paid by
Benton-Vinccler to local utilities. Benton-Vinccler used the proceeds from the
sale to repay indebtedness that was collateralized by a time deposit of the
Company. Permanent repayment of a portion of the loan allowed the Company to
reduce the cash collateral for the loan thereby making such cash available for
working capital needs.
In December 1999, the Company entered into agreements with Schlumberger and
Helmerich & Payne to further develop the Unit pursuant to a long-term
incentive-based development program. Schlumberger has agreed to financial
incentives intended to reduce drilling costs, improve initial production rates
of new wells and to increase the average life of the downhole pumps at South
Monagas. As part of Schlumberger's commitment to the program, it will provide
additional technical and engineering resources on-site full-time in Venezuela
and at the Company's offices in Carpinteria, California. Benton-Vinccler
commenced drilling in January 2000 with a one-rig program initially, and may add
a second rig in late 2000 or in 2001, depending on the results of current
drilling and production activities.
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 the 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 is the operator of the field and,
therefore, the Company is not 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 4). As of December 31, 1998, the Company's share of expenditures to date
was $8.2 million, which was included in the Venezuela cost center after
evaluation for proved reserves, and the standby letter of credit had been
reduced to $11.2 million. During 1999, the Block's first exploration well, the
Jarina 1-X, penetrated a thick potential reservoir sequence, but encountered no
hydrocarbons. The Company continues to evaluate the remaining leads on the
Block, including their potential reserves and risk factors, although the Block's
future commerciality is uncertain. As of March 31, 2000, the Company's share of
expenditures to date was $15.3 million, all of which had been included in the
Venezuela cost center, and the standby letter of credit had been reduced to $7.7
million.
NOTE 9 - 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
<PAGE> 17
17
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 for 1999. 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 held 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 was 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). Pursuant to the farmout agreement, the
Company was required to pay 100% of the first $8 million of the costs for the
phase one exploration period, after which any development costs were to be
shared equally. During the first six months of 1999, the first exploratory well
on the Qingshui Block was drilled to a total depth of 4,500 meters, and two
reservoirs, the Sha-2 and Sha-3, were tested. Although hydrocarbons were
encountered during drilling of the Qing Deep 22, Benton and operator Shell
concluded in the third quarter that the well was non-commercial. As a result,
the Company elected not to continue to the second exploration phase and has
relinquished its interest in the Block. Accordingly, the Company recognized a
write-down of the capitalized cost related to the farmout agreement of $12.6
million in the third quarter of 1999.
NOTE 10 - SANTA BARBARA OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases ("California 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 California Leases, the Company became the
operator of the project and agreed to pay 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. In November 1998, the Company
entered into an agreement to acquire Molino Energy's interest in the California
Leases in exchange for the release of its joint interest billing obligations,
but the transaction has not yet been finalized. In the fourth quarter of 1999,
the Company decided to focus its capital expenditures on existing producing
properties and fulfilling work commitments associated with its other properties.
Because the Company currently has no firm approved plans to continue drilling on
the California Leases and the 2199 #7 exploratory well did not result in
commercial reserves, the Company wrote off all of the capitalized costs
associated with the California Leases of $9.2 million and the joint interest
receivable of $3.1 million due from Molino Energy at December 31, 1999.
NOTE 11 - 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 eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which has been extended to
May 2000, for which it posted a $1 million standby letter of credit,
collateralized in full by a time deposit of the Company. During the first
quarter of 1998, the Company reentered two wells and tested two different
reservoirs. The WS-9 well tested significant, but non-commercial amounts of gas;
the WS-10 well resulted in no commercial amount of hyrdrocarbons. Therefore, at
December 31, 1998, the Company wrote down $3.7 million in capitalized costs
incurred to date related to the PSA. During 1999, the Company incurred an
additional $0.3 million in capitalized costs, which were written off at December
31, 1999. The Company does not expect that the PSA will be extended beyond its
May 17, 2000 expiration date. As a result, the Company expects to record a
liability to the NRA for the obligation remaining under the PSA, resulting in
impairment expense of approximately $1 million, during the second quarter of
2000.
<PAGE> 18
18
NOTE 12 - RELATED PARTY TRANSACTIONS
From 1996 through 1998, the Company made unsecured loans to its then Chief
Executive Officer, A. E. Benton. Each of these loans was evidenced by a
promissory note bearing interest at the rate of 6% per annum. The Company then
obtained a security interest in Mr. Benton's shares of stock, 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 exceeded
the value of the Company's collateral, 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. The portion of the note secured by the Company's stock
and stock options, $2.1 million, was presented on the Balance Sheet as a
reduction from Stockholders' Equity at December 31, 1998. 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. The Company recorded an additional $2.8 million allowance for
doubtful accounts for the remaining principal and accrued interest owed to the
Company at June 30, 1999, and continues to record additional allowances as
interest accrues ($0.2 million for the period July 1, 1999 to March 31, 2000).
Measuring the amount of the allowances requires judgements and estimates, and
the amount eventually realized may differ from the estimate.
In February 2000, the Company entered into a Separation Agreement and a
Consulting Agreement with Mr. Benton, pursuant to which the Company retained Mr.
Benton as an independent contractor to perform certain services for the Company.
At the same time, Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the full repayment of the Company's loans to
Mr. Benton, including all principal and accrued and accruing interest at the
rate of 6% per annum. Under the proposed plan, which the Company anticipates
will be submitted to the bankruptcy court in the second quarter of 2000, the
Company will retain its security interest in Mr. Benton's 600,000 shares of the
Company's stock and in his stock options, and in a portion of certain proceeds
of his Consulting Agreement. Repayment of the Company's loans to Mr. Benton may
be achieved through Mr. Benton's liquidation of certain real and personal
property assets; a phased liquidation of Company stock resulting from Mr.
Benton's exercise of his Company stock options; and, if necessary, from the
retained interest in the portion of the Consulting Agreement's proceeds. The
amount eventually realized by the Company and the timing of its receipt of
payments will depend upon the timing and results of the liquidation of Mr.
Benton's assets.
Under the terms of the Consulting Agreement, Mr. Benton will be paid consulting
fees of $485,000 for 2000, reducing to $322,000 in 2001, $240,000 in 2002, and a
declining consulting fee for the remainder of the term which expires December
31, 2006. Mr. Benton will also be entitled to certain additional incentive
bonuses with respect to cash receipts to the Company in connection with the
operations or divestiture of Geoilbent, Ltd. and Arctic Gas. To the extent that
Mr. Benton continues to be a consultant of the Company, his unvested stock
options will continue to vest and for a period of twelve (12) months thereafter.
Mr. Benton's consulting services will relate principally to the Company's
Russian activities.
Also during 1997 and 1996, the Company made loans to Mr. M.B. Wray, its Vice
Chairman and Mr. J.M. Whipkey, its then Chief Financial Officer, each loan
bearing interest at 6% and collateralized by a security interest in personal
real estate. On May 11, 1999, Mr. Wray repaid the entire balance of principal
and interest on his loan and on April 25, 2000, Mr. Whipkey repaid the entire
balance of principal and interest on his loan. The balance owed to the Company
by Mr. Whipkey was $0.3 million and $0.4 million at March 31, 2000 and December
31, 1999, respectively.
In addition, loans and other receivables (including travel advances) from other
employees (including one former employee) and directors to the Company totaled
$0.2 million at March 31, 2000 and December 31, 1999.
<PAGE> 19
19
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 the Company's Form 10-K for the year ended December 31, 1999
and its other 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
The Company includes the results of operations of Benton-Vinccler in its
consolidated financial statements and reflects the 20% ownership interest of
Vinccler as a minority interest. Geoilbent and Arctic Gas have been included in
the consolidated financial statements based on a fiscal period ending September
30. Results of operations for Geoilbent and Arctic Gas reflect the three months
ended December 31, 1998 and 1999. The Company's investment in Geoilbent and
Arctic Gas is accounted for using the equity method. Oil and gas reserve
information reflects the Company's 34% ownership interest of Geoilbent and its
unrestricted 25% ownership interest of Arctic Gas.
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 audited by
independent petroleum engineers. Costs amortized include all capitalized costs
(less accumulated amortization and impairment), 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 the Consolidated Financial Statements).
Statement of Financial Accounting Standards No. 133 ("SFAS 133"), as amended,
establishes accounting and reporting standards for derivative instruments and
hedging activities. The Company has not used derivative or hedging instruments
since 1996, but may consider hedging some portion of its oil production in the
future. The Company does not believe, however, that the adoption of SFAS 133
will have a material effect on its results of operations or financial position.
The following discussion of the results of operations for the three months ended
March 31, 2000 and 1999 and financial condition as at March 31, 2000 and
December 31, 1999 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, 2000
reflected the results for Benton-Vinccler, C.A. in Venezuela, which accounted
for 100% of the Company's production and oil sales revenue. As a result of
increases in world crude oil prices which were partially offset by lower
production from the South Monagas Unit, oil sales in Venezuela were 95% higher
in 2000 compared to 1999 with a 133% increase in realized fees per barrel (from
$6.05 in 1999 to $14.08 in 2000) and a 16% decrease in oil sales quantities
(from 2,659,085 barrels of oil in 1999 to 2,232,037 barrels of oil in 2000).
Operating expenses from the South Monagas Unit decreased 7% primarily due to a
reduction in workovers which was partially offset by an increase in electricity
expense.
<PAGE> 20
20
The following table presents selected expense items from the Company's
consolidated income statement items as a percentage of oil sales:
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
----------------------------
2000 1999
-------- --------
<S> <C> <C>
Operating Expenses 30% 63%
Depletion, Depreciation and Amortization 12 29
General and Administrative 14 30
Taxes Other Than on Income 3 4
Interest 24 47
</TABLE>
THREE MONTHS ENDED MARCH 31, 2000 AND 1999
The Company had revenues of $31.4 million for the three months ended March 31,
2000. Expenses incurred during the period consisted of operating expenses of
$9.4 million, depletion, depreciation and amortization expense of $3.8 million,
general and administrative expense of $4.4 million, taxes other than on income
of $1.1 million, interest expense of $7.4 million, income tax expense of $4.6
million and minority interest of $1.6 million. Other items of income consisted
of investment income and other of $2.0 million, net gain on exchange rates of
$0.2 million and equity in net earnings of affiliated companies of $1.7 million.
Net income was $3.0 million or $0.10 per share (diluted).
By comparison, the Company had revenues of $16.1 million for the three months
ended March 31, 1999. Expenses incurred during the period consisted of operating
expenses of $10.1 million, depletion, depreciation and amortization expense of
$4.7 million, general and administrative expense of $4.8 million, taxes other
than on income of $0.7 million, interest expense of $7.5 million, income tax
expense of $0.8 million and minority interest of $0.2 million. Other items of
income consisted of investment income and other of $2.5 million, net gain on
exchange rates of $0.4 million and equity in net earnings of affiliated
companies of $1.0 million. Net loss was $8.7 million or $0.29 per share
(diluted).
Revenues increased $15.3 million, or 95%, during the three months ended March
31, 2000 compared to the corresponding period of 1999 due to increased oil sales
revenue in Venezuela as a result of increases in world crude oil prices
partially offset by lower sales quantities. Sales quantities for the three
months ended March 31, 2000 from Venezuela were 2,232,037 barrels compared to
2,659,085 barrels for the three months ended March 31, 1999. The decrease in
sales quantities of 427,048 barrels or 16% was due primarily to the curtailment
in 1999 of the Venezuelan development drilling program. Prices for crude oil
averaged $14.08 per barrel (pursuant to terms of an operating service agreement)
from Venezuela compared to $6.05 per barrel for the corresponding period of
1999.
Operating expenses decreased $0.7 million, or 7%, during the three months ended
March 31, 2000 compared to the three months ended March 31, 1999 primarily due
to reduced oil production in Venezuela. Depletion, depreciation and amortization
decreased $0.9 million, or 19%, during the three months ended March 31, 2000
compared to the corresponding period of 1999 primarily due to reduced oil sales.
Depletion expense per barrel of oil equivalent produced from Venezuela during
the three months ended March 31, 2000 was $1.48 compared to $1.57 during the
corresponding period of the previous year. General and administrative expenses
decreased $0.4 million, or 8%, during the three months ended March 31, 2000
compared to the corresponding period of 1999 primarily due to the Company's
reduction in force in the fourth quarter of 1999 and other cost cutting
measures. Taxes other than on income increased $0.4 million, or 57%, during the
three months ended March 31, 2000 compared to the corresponding period of 1999
primarily due to increased Venezuelan municipal taxes, which are a function of
oil revenues.
Investment income and other decreased $0.5 million, or 20%, during the three
months ended March 31, 2000 compared to the three months ended March 31, 1999
due to lower average cash and marketable securities balances. Interest expense
decreased $0.1 million, or 1%, during the three months ended March 31, 2000
compared to the three months ended March 31, 1999 primarily due to reduced debt
outstanding substantially offset by the reduction of capitalized interest
expense. Net gain on exchange rates decreased $0.2 million, or 50% for the three
months ended March 31, 2000 compared to the corresponding period of 1999 due to
changes in the value of the Bolivar. The Company realized income before income
taxes and minority interest of $7.5 million during the three months ended March
31, 2000 compared to a loss of $8.8 million in the corresponding period of 1999,
which resulted in increased income tax expense of $3.8 million, or 475%. The
income attributable to the minority interest increased $1.4 million, or 700%,
for the three months ended March 31, 2000 compared to the three months ended
March 31, 1999 primarily due to the increased profitability of Benton-Vinccler.
The increase was partially offset by losses attributable to the minority
shareholders of Benton-Vinccler that were included in the consolidated net loss
of the Company during the first quarter of 1999 because the minority
shareholders' losses exceeded their interest in equity capital.
Equity in net earnings of affiliated companies increased $0.7 million, or 68%,
during the three months ended March 31, 2000 compared to the three months ended
March 31, 1999 primarily due to the increased income from Geoilbent. The
Company's share of revenues from Geoilbent were $5.9 million for the three
months ended December 31, 1999 compared to revenues of $1.9 million for the
three month period ended December 31, 1998. The increase of $4.0 million, or
211%, was due to
<PAGE> 21
21
significantly higher world crude oil prices and higher production. Prices for
Geoilbent's crude oil averaged $14.55 per barrel during the three months ended
December 31, 1999 compared to $5.65 for the three months ended December 31,
1998. The Company's share of Geoilbent oil sales quantities increased by 74,083
barrels, or 22%, from 333,102 barrels produced during the three months ended
December 31, 1998 to 407,185 barrels produced during the three months ended
December 31, 1999.
DOMESTIC OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases ("California 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 California 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. In November 1998, the Company entered into an
agreement to acquire Molino Energy's interest in the California Leases in
exchange for the release of its joint interest billing obligations, but the
transaction has not yet been finalized. In the fourth quarter of 1999, the
Company decided to focus its capital expenditures on existing producing
properties and fulfilling work commitments associated with its other properties.
Because the Company currently has no firm approved plans to continue drilling on
the California Leases and the 2199 #7 exploratory well did not result in
commercial reserves, the Company wrote off all of the capitalized costs
associated with the California Leases of $9.2 million and the joint interest
receivable of $3.1 million due from Molino Energy at December 31, 1999.
INTERNATIONAL OPERATIONS
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 1998 due to the effect of the devaluation of the Bolivar while
Benton-Vinccler uses the U.S dollar as its functional currency. The effective
tax rate for 1999 was lower due to a decrease in the 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, and a
371 kilometer 2-D seismic survey has been acquired for, the Delta Centro Block
in Venezuela. During 1999, the Block's first exploration well, the Jarina 1-X,
penetrated a thick potential reservoir sequence, 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. The
total cost to the Company of acquiring the seismic data and drilling the Jarina
1-X was $15.3 million. 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%.
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 of 15 Euros per ton ($1.97 per barrel)
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 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 that 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. At March 31, 2000, 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 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 eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which has been extended to
May 2000, for which it posted a $1 million standby letter of credit,
collateralized in full by a time deposit of
<PAGE> 22
22
the Company. During the first quarter of 1998, the Company reentered two wells
and tested two different reservoirs. The WS-9 well tested significant, but
non-commercial amounts of gas; the WS-10 well resulted in no commercial amounts
of hydrocarbons. Therefore, at December 31, 1998, the Company wrote down $3.7
million in capitalized costs incurred to date related to the PSA. During 1999,
the Company incurred an additional $0.3 million in capitalized costs, which were
written off at December 31, 1999. The Company does not expect that the PSA will
be extended beyond its May 17, 2000 expiration date. As a result, the Company
expects to record a liability to the NRA for the obligation remaining under the
PSA, resulting in impairment expense of approximately $1 million, during the
second quarter of 2000.
In October 1999, the Company entered into an agreement with First Seismic
Corporation ("First Seismic") whereby the Company, upon receiving a release from
Petrosen of its remaining work commitment, transferred its entire working
interests in the Thies Block and paid $0.7 million to First Seismic in exchange
for 135,000 series B preferred shares of First Seismic. The Company performed a
valuation of the securities at the date of the agreement with First Seismic and
concluded that the securities had a de minimis fair value. Accordingly, the
Company has not assigned any cost to the securities. For the year ended December
31, 1999, the Company recorded a write-down of $1.6 million comprised of $0.9
million of previously capitalized costs and $0.7 million of payment to First
Seismic. At March 31, 2000, the Company evaluated the securities and believes
that the fair value of the securities has not changed since the date of the
agreement.
In April 1998, the Company signed an agreement to earn a 40% equity interest in
Arctic Gas. Arctic Gas owns the exclusive rights to evaluate, develop and
produce the natural gas, condensate, and oil reserves in the Samburg and
Yevo-Yakha License Blocks in West Siberia. The two blocks comprise 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 Arctic Gas,
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 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 received
voting shares representing a 40% ownership in Arctic Gas that contain
restrictions on their sale and transfer. The Share Disposition Agreement
provides for removal of the restrictions as disbursements are made under the
credit facility. Due to the significant influence it exercises over the
operating and financial policies of Arctic Gas, the Company has accounted for
its interest in Arctic Gas using the equity method. Certain provisions of
Russian corporate law would effectively require minority shareholder consent to
enter into new agreements between the Company and Arctic Gas, or to change any
terms in any existing agreements, including the conditions upon which the
restrictions on the shares could be removed, between the two such as the
Cooperation Agreement and the Share Disposition Agreement.
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION
The Company's results of operations and cash flow are affected by changing oil
prices. However, the Company's Venezuelan 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, which dampens both any upward and downward effects of
changing prices on the Company's Venezuelan oil sales and cash flows. If the
price of oil 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 oil sales. 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
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, a significant majority 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. If
the rate of increase in the value of the dollar compared to the bolivar
continues to be less than the rate of inflation in Venezuela, then inflation
could be expected to have an adverse effect on Benton-Vinccler.
During the three months ended March 31, 2000, 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, 2000, the Company's net foreign exchange gains and losses attributable
to its Venezuelan and Russian operations, respectively, were $0.2 million and
$0.1 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
<PAGE> 23
23
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 are summarized in the following table and discussed in
further detail below:
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
----------------------------
(IN THOUSANDS)
2000 1999
------------ -----------
<S> <C> <C>
Net cash provided by operating activities $ 19,432 $ 4,898
Net cash used in investing activities (10,854) (10,813)
Net cash provided by (used in) financing activities 664 (95)
-------- --------
Net increase (decrease) in cash $ 9,242 $ (6,010)
======== ========
</TABLE>
At March 31, 2000, the Company had current assets of $70.0 million and current
liabilities of $42.8 million, resulting in working capital of $27.2 million and
current ratio of 1.64:1. This compares to the Company's working capital of $32.1
million and a current ratio of 2.17:1 at December 31, 1999. The decrease in
working capital of $4.9 million was primarily due to capital expenditures at the
South Monagas Unit in Venezuela and additional investments in and advances to
Arctic Gas Company during the three months ended March 31, 2000.
CASH FLOW FROM OPERATING ACTIVITIES. During the three months ended March 31,
2000 and 1999, net cash provided by operating activities was approximately $19.4
million and $4.9 million, respectively. Cash flow from operating activities
increased by $14.5 million during the three months ended March 31, 2000 compared
to the corresponding period of 1999 due primarily to increased collections of
accrued oil revenues. Collections of accrued oil revenues increased $12.9
million, or 85%, during the three months ended March 31, 2000 compared to the
corresponding period of 1999 due to higher prices received on sales from the
South Monagas Unit in Venezuela.
CASH FLOW FROM INVESTING ACTIVITIES. During the three months ended March 31,
2000 and 1999, the Company had drilling and production related capital
expenditures of approximately $10.3 million and $15.0 million, respectively. Of
the 2000 expenditures, $10.0 million was attributable to the development of the
South Monagas Unit in Venezuela, $0.1 million related to costs on the Delta
Centro Block in Venezuela, $0.2 million was attributable to other projects.
In August 1999, Benton-Vinccler sold its recently-constructed power generation
facility located in the Uracoa field of the South Monagas Unit in Venezuela for
$15.1 million. Concurrently with the sale, Benton-Vinccler entered into a
long-term power purchase agreement with the purchaser of the facility to provide
for the electrical needs of the field throughout the remaining term of the
operating service agreement. The cost of electricity to be provided under terms
of the power purchase agreement approximates that previously paid by
Benton-Vinccler to local utilities. Benton-Vinccler used the proceeds from the
sale to repay indebtedness that was collateralized by a time deposit of the
Company. Permanent repayment of a portion of the loan allowed the Company to
reduce the cash collateral for the loan thereby making such cash available for
working capital needs.
As a result of the decline in oil prices, the Company instituted in 1998, and
continued in 1999, a capital expenditure program to reduce expenditures to those
that the Company believed were necessary to maintain current producing
properties. In the second half of 1999, oil prices recovered substantially. In
December 1999, the Company entered into incentive-based development alliance
agreements with Schlumberger and Helmerich & Payne as part of its plans to
resume development of the South Monagas Unit in Venezuela.
The Company expects capital expenditures of approximately $57-63 million during
the next 12 months. Anticipated capital expenditures include approximately
$50-55 million at the South Monagas Unit and $7-8 million for Arctic Gas. In
addition, the
<PAGE> 24
24
Company anticipates providing or arranging loans of up to $100 million over time
to Arctic Gas pursuant to an equity acquisition agreement signed in April 1998.
The Company continues to evaluate funding alternatives for the loans to Arctic
Gas. The timing and size of the investments for the South Monagas Unit and
Arctic Gas are substantially at the Company's discretion. The Company
anticipates that Geoilbent will continue to fund its expenditures through its
own cash flow and credit facilities. The Company's remaining capital commitments
worldwide are relatively minimal and are substantially at the Company's
discretion. The Company will also be required to make interest payments of
approximately $25 million related to its outstanding senior notes during the
next 12 months.
The Company continues to assess production levels and commodity prices in
conjunction with its capital resources and liquidity requirements. The results
from the new wells drilled in the Uracoa Field in Venezuela under the alliance
agreements with Schlumberger and Helmerich & Payne indicate that the reservoir
formation quality is as expected, but may be sensitive to drilling and
completion practices. Additionally, a number of previously producing wells
have recently gone off production and are pending maintenance operations.
While the Company and its alliance partners are working on techniques to
optimize the production from new wells and are adding a rig to workover
existing wells, the recent production performance from the Uracoa Field has
not yet reached levels expected by the Company.
The Company's capital resources and liquidity are affected by the timing of its
semiannual interest payments of approximately $12.5 million each May 1 and
November 1 and by the quarterly payments from PDVSA at the end of the months of
February, May, August and November pursuant to the terms of the contract between
Benton Vinccler and PDVSA regarding the South Monagas Unit. As a consequence of
the timing of these interest payment outflows and the PDVSA payment inflows, the
Company's 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 the cash balances. The Company is currently in discussions with
two commercial banks regarding short-term working capital facilities to smooth
out these large cash balance fluctuations.
Based upon revised expectations regarding production levels and pricing, the
Company anticipates that its ability to fund its planned South Monagas Unit
capital expenditures and its semi-annual interest payment obligations for the
next 12 months will require, in addition to its working capital and cash flow
from operations, short term borrowings for working capital purposes in the range
of $10-15 million during the time periods between the submission of the
quarterly invoices to PDVSA by Benton-Vinccler and the subsequent payments by
PDVSA of those invoices, which can be up to 60 days after the end of the
quarter. The Company currently believes that such working capital sources will
be available. If additional funds are needed, the Company will be required to
pursue one or more of the following alternatives: reduce its South Monagas
Unit, Arctic Gas Company, and other capital expenditures significantly,
substantially all of which are within its discretion; sell property interests;
form joint ventures or alliances with financial or other industry partners;
merge or combine with another entity; or issue debt or equity securities. There
can be no assurance that any of the alternatives will be available on terms
acceptable to the Company.
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production, oil production quantities
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.
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, 2000, the Company was in compliance with all
covenants of the indentures.
RESTRUCTURING
In an effort to reduce general and administrative expenses, the Company reduced
its administrative and technical staff in Carpinteria by 10 persons in October
1999. In connection with the reduction in staff, the Company recorded
termination benefits expenses in October 1999 of $0.8 million that are payable
from October 1999 through September 2000. The unpaid portion of these benefits
of $0.1 million is included in Accrued Expenses at March 31, 2000.
YEAR 2000 COMPLIANCE
The Company has completed addressing the Year 2000 issue for critical systems
and applications. As of the filing date of this Form 10-Q, the Company's
business operations have not been materially impacted by the Year 2000 issue.
The Company will no longer report on the Year 2000 issue.
<PAGE> 25
25
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from adverse changes in oil and gas
prices, interest rates and foreign exchange, as discussed below.
OIL AND GAS PRICES
As an independent oil and gas producer, the Company's revenue, other income and
equity earnings and profitability, reserve values, access to capital and future
rate of growth are substantially dependent upon the prevailing prices of crude
oil and condensate. The Company currently neither produces nor records reserves
related to 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 the control of the Company.
Historically, prices received for oil and gas production have been volatile and
unpredictable, and such volatility is expected to continue. This volatility is
demonstrated by the average realizations in Venezuela, which declined from
$10.01 in 1997 to $6.75 in 1998 and increased to $14.08 in the first quarter of
2000. From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve a more predictable
cash flow, as well as to reduce its exposure to price fluctuations, but the
Company has utilized no such transactions since 1996. While hedging limits the
downside risk of adverse price movements, it may also limit future revenues from
favorable price movements. Because gains or losses associated with hedging
transactions are included in oil sales when the hedged production is delivered,
such gains and losses are generally offset by similar changes in the realized
prices of the commodities. The Company did not enter into any commodity hedging
agreements during the three months ended March 31, 2000.
INTEREST RATES
Total long term debt was $264.6 million at March 31, 2000, including $230
million of fixed-rate senior unsecured notes maturing in 2003 ($125 million) and
2007 ($105 million). Another $34.6 million of debt is attributable to a
floating-rate back-to-back loan facility wherein Benton-Vinccler pays
floating-rate interest to a bank, which then pays to the Company interest on
cash collateral deposited by the Company to support the loans, such interest to
the Company being equal to the floating rate payment less approximately 0.375%
thereby mitigating the floating-rate interest rate risk of such debt. A
hypothetical 10% adverse change in the floating rate would not have had a
material affect on the Company's results of operations for the three months
ended March 31, 2000.
FOREIGN EXCHANGE
The Company's operations are located primarily outside of the United States. In
particular, the Company's current oil producing operations are located in
Venezuela and Russia, countries which have had recent histories of significant
inflation and devaluation. For the Venezuelan operations, oil sales are received
under a contract in effect through 2012 in US dollars; expenditures are both in
US dollars and local currency. For the Russian operations, a majority of the oil
sales are received in US dollars; expenditures are both in US dollars and local
currency, although a larger percentage of the expenditures were in local
currency. The Company has utilized no currency hedging programs to mitigate any
risks associated with operations in these countries, and therefore the Company's
financial results are subject to favorable or unfavorable fluctuations in
exchange rates and inflation in these countries.
<PAGE> 26
26
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> 27
27
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, 2000 By: /S/Michael B. Wray
----------------------------------
Michael B. Wray
Acting Chief Executive Officer
Dated: May 12, 2000 By: /S/David H. Pratt
----------------------------------
David H. Pratt
Senior Vice President and Chief
Financial Officer
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
FOR THE PERIOD ENDED MARCH 31, 2000 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-START> JAN-01-2000
<PERIOD-END> MAR-31-2000
<EXCHANGE-RATE> 1
<CASH> 30,389
<SECURITIES> 2,529
<RECEIVABLES> 30,643
<ALLOWANCES> 6,269
<INVENTORY> 0
<CURRENT-ASSETS> 70,013
<PP&E> 455,820
<DEPRECIATION> 363,091
<TOTAL-ASSETS> 296,496
<CURRENT-LIABILITIES> 42,845
<BONDS> 264,575
0
0
<COMMON> 297
<OTHER-SE> (14,267)
<TOTAL-LIABILITY-AND-EQUITY> 296,496
<SALES> 31,433
<TOTAL-REVENUES> 31,433
<CGS> 13,188
<TOTAL-COSTS> 13,188
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7,445
<INCOME-PRETAX> 7,538
<INCOME-TAX> 4,636
<INCOME-CONTINUING> 2,995
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,995
<EPS-BASIC> 0.10
<EPS-DILUTED> 0.10
</TABLE>
