<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 September 30, 1999 or
Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from to _____
COMMISSION FILE NO. 1-10762
-------------------
BENTON OIL AND GAS COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 77-0196707
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
6267 CARPINTERIA AVE., SUITE 200
CARPINTERIA, CALIFORNIA 93013
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (805) 566-5600
-------------------
Indicate by check mark whether the Registrant (1) has
filed all reports required to be filed by Section 13
or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that
the Registrant was required to file such reports), and
(2) has been subject to such filing requirements for the
past 90 days.
Yes X No
--- ---
-------------------
At November 12, 1999, 29,576,966 shares of the
Registrant's Common Stock were outstanding.
<PAGE> 2
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
<TABLE>
<CAPTION>
Page
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PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
<S> <C> <C>
Consolidated Balance Sheets at September 30, 1999
and December 31, 1998 (Unaudited)..................................................3
Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 1999 and 1998 (Unaudited)...............................4
Consolidated Statements of Cash Flows for the Nine
Months Ended September 30, 1999 and 1998 (Unaudited)...............................5
Notes to Consolidated Financial Statements..........................................7
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS................................................17
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
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, unaudited)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
--------------- ------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 23,380 $ 18,147
Restricted cash 12 12
Marketable securities 16,334 41,173
Accounts and notes receivable:
Accrued oil and gas revenue 24,881 17,307
Joint interest and other, net 8,733 12,482
Prepaid expenses and other 3,009 3,688
--------- ----------
TOTAL CURRENT ASSETS 76,349 92,809
RESTRICTED CASH 47,311 65,670
OTHER ASSETS 10,689 11,725
DEFERRED INCOME TAXES 3,231 2,976
INVESTMENT IN AND ADVANCES TO AFFILIATED COMPANY 20,943 11,975
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of $31,578 and
$35,228 excluded from amortization in 1999 and 1998, respectively) 500,557 483,494
Furniture and fixtures 9,629 9,608
--------- ----------
510,186 493,102
Accumulated depletion, impairment and depreciation (368,462) (339,636)
--------- ----------
141,724 153,466
--------- ----------
$300,247 $338,621
========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other $ 5,036 $ 10,014
Accrued interest payable 10,393 5,527
Accrued expenses 20,463 19,342
Income taxes payable 2,834 1,847
Current portion of long term debt 65 215
--------- ----------
TOTAL CURRENT LIABILITIES 38,791 36,945
LONG TERM DEBT 275,713 288,212
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST 1,007 475
STOCKHOLDERS' EQUITY:
Preferred stock, par value $0.01 a share; authorized 5,000 shares;
outstanding, none - -
Common stock, par value $0.01 a share; authorized 80,000 shares;
issued 29,627 shares at September 30, 1999 and
December 31, 1998 296 296
Additional paid-in capital 147,056 147,054
Retained deficit (161,917) (131,569)
Treasury stock, at cost, 50 shares (699) (699)
Employee note receivable, net - (2,093)
--------- ----------
TOTAL STOCKHOLDERS' EQUITY (15,264) 12,989
--------- ----------
$300,247 $338,621
========= ==========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 4
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data, unaudited)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ ------------------------------
1999 1998 1999 1998
------------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
REVENUES
Oil sales $ 26,922 $ 20,030 $ 67,312 $ 72,157
Gain (loss) on exchange rates (120) 526 2,435 2,025
Investment earnings and other 2,325 3,323 7,172 11,163
----------- ---------- ---------- ----------
29,127 23,879 76,919 85,345
----------- ---------- ---------- ----------
EXPENSES
Lease operating costs and production taxes 11,367 10,610 32,607 35,352
Depletion, depreciation and amortization 4,514 7,719 15,009 28,664
Write-down and impairment of oil and gas properties 13,047 - 14,322 71,467
General and administrative 5,392 5,244 19,457 16,696
Interest 7,313 8,244 22,841 24,354
----------- ---------- ---------- ----------
41,633 31,817 104,236 176,533
----------- ---------- ---------- ----------
LOSS BEFORE INCOME TAXES
AND MINORITY INTEREST (12,506) (7,938) (27,317) (91,188)
INCOME TAX EXPENSE (BENEFIT) 1,446 197 2,499 (7,767)
---------- ---------- ---------- ----------
LOSS BEFORE MINORITY INTEREST (13,952) (8,135) (29,816) (83,421)
MINORITY INTEREST 177 (296) 532 (4,553)
---------- ---------- ---------- ----------
NET LOSS $ (14,129) $ (7,839) $ (30,348) $ (78,868)
NET LOSS PER COMMON SHARE:
Basic $ (0.48) $ (0.27) $ (1.03) $ (2.67)
========== ========== ========== ==========
Diluted $ (0.48) $ (0.27) (1.03) (2.67)
========== ========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 5
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
(In thousands, unaudited)
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------------------
1999 1998
------------------ ------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss $ (30,348) $ (78,868)
Adjustments to reconcile net loss to net cash provided by operating
activities:
Depletion, depreciation and amortization 15,009 28,664
Write-down of oil and gas properties 14,322 71,467
Amortization of financing costs 1,179 964
Loss on disposition of assets 39 72
Allowance for employee notes and accounts receivable 2,868 -
Minority interest in undistributed earnings of subsidiary 532 (4,551)
Deferred income taxes (255) (12,342)
Changes in operating assets and liabilities:
Accounts receivable (4,600) 14,602
Prepaid expenses and other 679 622
Accounts payable (4,978) (12,047)
Accrued interest payable 4,866 6,229
Accrued expenses 1,121 2,456
Income taxes payable 987 585
------------ -------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 1,421 17,853
------------ -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and equipment 15,000 -
Additions of property and equipment (32,572) (97,410)
Investment in and advances to affiliated company (8,968) (5,156)
Increase in restricted cash (213) (194)
Decrease in restricted cash 18,572 -
Purchase of marketable securities (26,766) (49,389)
Maturities of marketable securities 51,605 134,662
---------- -------------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 16,658 (17,487)
---------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from exercise of stock options and warrants 2 795
Proceeds from issuance of short term borrowings and notes payable 3,412 6,810
Payments on short term borrowings and notes payable (16,061) (89)
Increase in other assets (199) (2,584)
----------- ------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (12,846) 4,932
----------- ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 5,233 5,298
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 18,147 11,940
----------- ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 23,380 $ 17,238
=========== ============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for interest expense $ 18,267 $ 16,858
=========== ============
Cash paid during the period for income taxes $ 899 $ 3,634
=========== ============
</TABLE>
(continued)
<PAGE> 6
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the nine months ended September 30 1999, the Company recorded an
allowance for doubtful accounts related to amounts owed to the Company by its
former Chief Executive Officer (see Note 12). The portion of the allowance
related to amounts secured by the Company's stock and stock options was
$2,093,000.
During 1996 and 1997, the Company incurred $4.1 million in financing costs
related to the establishment of the EBRD financing (see Note 6). In 1998, under
an agreement with EBRD, GEOILBENT's board ratified an agreement to reimburse the
Company for $2.6 million of such costs, and accordingly, during the nine months
ended September 30, 1998, the Company recorded these costs as an account
receivable from GEOILBENT.
See accompanying notes to consolidated financial statements.
<PAGE> 7
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
-------------------------------------------
NINE MONTHS ENDED SEPTEMBER 30, 1999 (UNAUDITED)
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Benton Oil and Gas Company (the "Company") engages in the exploration,
development, production and management of oil and gas properties. The Company
conducts its business in Venezuela, Russia, the United States, China, Jordan and
Senegal.
The consolidated financial statements include the accounts of the Company and
its subsidiaries. The Company's investment in GEOILBENT, its Russian joint
venture, is accounted for using proportionate consolidation based on the
Company's ownership interest. The Company's investment in Arctic Gas Company
("Arctic Gas"), formerly Severneftegaz, a Russian open joint stock company, is
accounted for using the equity method because of the significant influence the
Company exercises over its operations and management. All intercompany profits,
transactions and balances have been eliminated. The Company accounts for its
investment in GEOILBENT and Arctic Gas based on a fiscal year ending September
30.
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 (see
Capital Resources and Liquidity in Item 2-Management's Discussion and Analysis
of Financial Condition and Results of Operations). On November 10, 1999, the
Company announced that it has entered into a letter of intent with Schlumberger
Oilfield Services ("Schlumberger") to form a long term incentive-based alliance
as part of its plans to resume development of the South Monagas Field in
Venezuela (see Note 7).
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuation in response to change in supply, market uncertainty and a variety of
factors beyond the Company's control.
The Company believes its current cash and cash to be provided by operating
activities will be sufficient to meet the Company's liquidity needs for routine
operations and to service its outstanding debt through November 2000. However,
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, operating and administrative expenditures,
form strategic joint ventures or alliances with other industry partners, sell
property interests, merge or combine with another entity, or issue debt or
equity securities. However, 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 September 30,
1999, and the results of operations for the three and nine month periods ended
September 30, 1999 and 1998. The unaudited financial statements are presented in
accordance with the requirements of Form 10-Q and do not include all disclosures
normally required by generally accepted accounting principles. Reference should
be made to the Company's consolidated financial statements and notes thereto
included in the Company's Annual Report on Form 10-K for the year ended December
31, 1998 for additional disclosures, including a summary of the Company's
accounting policies.
The results of operations for the three and nine month periods ended September
30, 1999 are not necessarily indicative of the results to be expected for the
full year.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
<PAGE> 8
ACCOUNTS AND NOTES RECEIVABLE
The Company's allowance for doubtful accounts related to employee notes and
accounts receivable and other accounts receivable was $6.1 million at September
30, 1999 and $3.2 million at December 31, 1998 (see Note 12).
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, as of September 30, 1999, losses attributable to the minority
shareholder of Benton-Vinccler, a subsidiary owned 80% by the Company, exceeded
its interest in equity capital creating an equity deficit. Accordingly, all of
Benton-Vinccler's net income for the nine month period ended September 30, 1999
attributable to the minority shareholder ($0.2 million) has been included in the
consolidated net loss of the Company. Income attributable to the minority
shareholder will be included in the consolidated results of the Company until
the minority shareholder's equity deficit is eliminated.
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 $16.3 million and $41.2 million in
commercial paper at September 30, 1999 and December 31, 1998, respectively.
COMPREHENSIVE INCOME
Statement of Financial Accounting Standards No. 130 ("SFAS 130") requires that
all items that are required to be recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements. However, the
Company did not have any items of other comprehensive income during the three
and nine month periods ended September 30, 1999 or 1998 and, in accordance with
SFAS 130, has not provided a separate statement of comprehensive income.
EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128 ("SFAS 128") "Earnings per Share." SFAS
128 replaces the presentation of primary earnings per share with a presentation
of basic earnings per share based upon the weighted average number of common
shares for the period. It also requires dual presentation of basic and diluted
earnings per share for companies with complex capital structures. SFAS 128 was
adopted by the Company in December 1997, and earnings per share for all prior
periods have been restated. The numerator (loss), denominator (shares) and
amount of the basic and diluted earnings per share computations were (in
thousands, except per share amounts):
<TABLE>
<CAPTION>
AMOUNT PER
LOSS SHARES SHARE
------------- ------------ ------------
<S> <C> <C> <C>
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 1999
---------------------------------------------
BASIC EPS
Loss attributable to common stockholders $(14,129) 29,577 $(0.48)
========= ======== ========
DILUTED EPS
Loss attributable to common stockholders $(14,129) 29,577 $(0.48)
========= ======== ========
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 1998
---------------------------------------------
BASIC EPS
Loss attributable to common stockholders $(7,839) 29,577 $(0.27)
========= ======== ========
DILUTED EPS
Loss attributable to common stockholders $(7,839) 29,577 $(0.27)
========= ======== ========
</TABLE>
<PAGE> 9
<TABLE>
<S> <C> <C> <C>
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
--------------------------------------------
BASIC EPS
Loss attributable to common stockholders $(30,348) 29,577 $(1.03)
========= ======= =======
DILUTED EPS
Loss attributable to common stockholders $(30,348) 29,577 $(1.03)
========= ======= =======
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1998
--------------------------------------------
BASIC EPS
Loss attributable to common stockholders $(78,868) 29,546 $(2.67)
========= ======= =======
DILUTED EPS
Loss attributable to common stockholders $(78,868) 29,546 $(2.67)
========= ======= =======
</TABLE>
An aggregate 6.0 million and 5.0 million options and warrants were excluded from
the earnings per share calculations because they were anti-dilutive for the
three months ended September 30, 1999 and 1998, respectively. An aggregate 5.0
million and 4.9 million options and warrants, were excluded from the earnings
per share calculations because they were anti-dilutive for the nine months ended
September 30, 1999 and 1998, respectively.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for oil and gas
properties. Accordingly, all costs associated with the acquisition, exploration,
and development of oil and gas reserves are capitalized as incurred, including
exploration overhead of $1.7 million and $1.8 million for the nine months ended
September 30, 1999 and 1998, respectively, and capitalized interest of $1.7
million for the nine months ended September 30, 1999. Only overhead which is
directly identified with acquisition, exploration or development activities is
capitalized. Interest is capitalized on significant investments in unproved
properties that are excluded from depletion, depreciation and amortization and
on which exploration activities are in progress. All costs related to
production, general corporate overhead and similar activities are expensed as
incurred. The costs of oil and gas properties are accumulated in cost centers on
a country by country basis, subject to a cost center ceiling (as defined by the
Securities and Exchange Commission). Pursuant to the ceiling limitation as a
result of declines in world crude oil prices, the Company recognized write downs
in the Venezuela and Russian cost centers for the nine months ended September
30, 1998 of $55.9 million and $10.1 million, respectively. Additionally, the
Company recognized write-downs of $5.5 million and $14.3 million during the nine
months ended September 30, 1998 and 1999, respectively of capitalized costs
associated with certain exploration activities.
All capitalized costs of oil and gas properties (excluding unevaluated property
acquisition and exploration costs) and the estimated future costs of developing
proved reserves, are depleted over the estimated useful lives of the properties
by application of the unit-of-production method using only proved oil and gas
reserves. Excluded costs attributable to the Russia, China and other cost
centers at September 30, 1999 were $5.4 million, $16.1 million, and $10.1
million, respectively. Excluded costs attributable to the Russia, China and
other cost centers at December 31, 1998 were $4.3 million, $20.5 million and
$10.4 million, respectively. Depletion expense attributable to the Venezuela and
Russia cost centers for the nine months ended September 30, 1999 was $11.5
million and $2.3 million ($1.55 and $2.11 per equivalent barrel), respectively.
Depletion expense attributable to the Venezuela and Russia cost centers for the
nine months ended September 30,1998 was $25.5 million and $2.2 million ($2.69
and $3.51 per equivalent barrel), respectively. Depreciation of furniture and
fixtures is computed using the straight-line method, with depreciation rates
based upon the estimated useful life applied to the cost of each class of
property. Depreciation expense was $1.2 million and $0.9 million for the nine
months ended September 30, 1999 and 1998, respectively.
RECLASSIFICATIONS
Certain items in 1998 have been reclassified to conform to the 1999 financial
statement presentation.
<PAGE> 10
NOTE 2 - LONG TERM DEBT
Long term debt consists of the following (in thousands):
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31, 1998
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. 34,937 50,000
Reserve-based loans with average interest
Rate of LIBOR plus 5.25%. See description below. 9,802 6,453
GEOILBENT credit facility collateralized by a time deposit of the
Company earning approximately 5.7%. See description below. 974 1,624
Other 65 350
--------- ---------
275,778 288,427
Less current portion 65 215
--------- ---------
$275,713 $ 288,212
========= =========
</TABLE>
In November 1997, the Company issued $115 million in 9.375% senior unsecured>
notes due November 1, 2007, of which the Company subsequently repurchased $10
million at their par value. In May 1996, the Company issued $125 million in
11.625% senior unsecured notes due May 1, 2003. Interest on the notes is due May
1 and November 1 of each year. The indenture agreements provide for certain
limitations on liens, additional indebtedness, certain investments and capital
expenditures, dividends, mergers and sales of assets. At September 30, 1999, the
Company was in compliance with all covenants of the indentures.
In August 1996, Benton-Vinccler entered into a $50 million, long term credit
facility with Morgan Guaranty Trust Company of New York ("Morgan Guaranty") to
repay the balance outstanding under a short term credit facility and to repay
certain advances received from the Company. In August 1999, Benton Vinccler
repaid $15.1 million of the long term credit facility with proceeds from the
sale of certain equipment located in the South Monagas Unit. 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.
As of September 30, 1999, GEOILBENT (owned 34% by the Company) has borrowed
$28.8 million under parallel reserve-based loan agreements with the European
Bank for Reconstruction and Development ("EBRD") and International Moscow Bank
("IMB"). EBRD and IMB have agreed to lend up to a total of $65 million to
GEOILBENT based on achieving certain reserve and production milestones. Under
these loan agreements, the Company and other shareholders of GEOILBENT have
significant management and business support obligations. Each shareholder is
jointly and severally liable to EBRD and IMB for any losses, damages,
liabilities, costs, expenses and other amounts suffered or sustained arising out
of any breach by any shareholder of its support obligations. The loans bear an
average interest rate of LIBOR plus 5.25% payable on January 27 and July 27 each
year. Principal payments will be due in varying installments on the semiannual
interest payment dates beginning July 27, 2000 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. The Company's share of the
amounts borrowed under the loan agreements was $9.8 million and $6.5 million at
September 30, 1999 and December 31, 1998, respectively.
In October 1995, GEOILBENT entered into an agreement with Morgan Guaranty for a
credit facility under which the Company provides cash collateral for the loans
to GEOILBENT. The credit facility is renewable annually. Loans outstanding under
the credit facility bear interest at either LIBOR plus 0.75%, subject to certain
adjustments, or the Morgan Guaranty prime rate plus 2%, whichever is selected at
the time a loan is made. In conjunction with GEOILBENT's reserve-based loan
agreements with the EBRD and IMB, repayment of the credit facility is
subordinated to payments due to the EBRD and IMB and, accordingly, the credit
facility is classified as long term. However, during the nine months ended
September 30, 1999, EBRD and IMB consented to the repayment of $2.0 million
($0.7 million to the Company) in
<PAGE> 11
exchange for the Company's capital contribution to GEOILBENT of $2.0 million.
The credit facility contains no restrictive covenants and no financial ratio
covenants.
NOTE 3 - COMMITMENTS AND CONTINGENCIES
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties and that it paid a
price in excess of the fair value of the property. A trial date has been
scheduled for December 6, 1999 and discovery is complete, unless reopened by the
court. 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, in December 1998, the letter of
credit was reduced to $11.2 million, and in July 1999, the standby letter of
credit was further reduced to $7.7 million.
The Company has employment contracts with four senior management personnel which
provide for annual base salaries, bonus compensation and various benefits. The
contracts provide for the continuation of salary and benefits for the respective
terms of the agreements in the event of termination of employment without cause.
These agreements expire at various times from December 31, 1999 to June 1, 2001.
The Company has also entered into employment agreements with eight individuals,
which provide for certain severance payments in the event of a change of control
of the Company and subsequent termination by the employees for good reason.
The Company has entered into various exploration and development contracts in
various countries which require minimum expenditures, some of which required
that the Company secure its commitments by providing letters of credit. The
Company has also entered into equity acquisition agreements in Russia which call
for the Company to provide or arrange for certain amounts of credit financing in
order to remove sale and transfer restrictions on the equity acquired or to
maintain ownership in such equity.
In 1998, the Company entered into a 15-year lease agreement for office space in
Carpinteria, California. The Company has leased 50,000 square feet for
approximately $74,000 per month with annual rent adjustments based on certain
changes in the Consumer Price Index. The Company has entered into a sublease
agreement for a portion of the office space which is not currently needed for
operations. The Company has also entered into a sublease agreement for the
office space that it previously occupied. Rents for the subleases approximate
the Company's lease costs of these facilities.
NOTE 4 - TAXES ON INCOME
At December 31, 1998, the Company had, for federal income tax purposes,
operating loss carryforwards of approximately $90 million expiring in the years
2003 through 2018. If the carryforwards are ultimately realized, approximately
$13 million will be credited to additional paid-in capital for tax benefits
associated with deductions for income tax purposes related to stock options.
During the nine months ended September 30, 1999, the Company recorded deferred
tax assets generated from current period operating losses and a valuation
allowance of $11.6 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
NOTE 5 - OPERATING SEGMENTS
The Company regularly allocates resources to and assesses the performance of its
operations by segments that are organized by unique geographic and operating
characteristics. The segments are organized in order to manage regional
business, currency and tax related risks and opportunities. Revenues from the
Venezuela and Russia operating segments are derived primarily from the
production and sale of oil. Revenues from United States and Other are derived
primarily from interest earnings on various investments and consulting revenues.
Operations included under the heading "United States 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
United States and Other segment and are not allocated to other operating
segments. The Company's investment in Arctic Gas has been included in the Russia
operating segment.
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
1999 1998 1999 1998
------------ --------- ----------- -----------
<S> <C> <C> <C> <C>
OPERATING SEGMENT REVENUES
Oil sales
Venezuela $ 24,565 $ 17,890 $ 61,006 $ 66,045
Russia 2,357 2,140 6,306 6,112
------------- ----------- ------------ ----------
Total oil sales 26,922 20,030 67,312 72,157
------------- ----------- ------------ ----------
Other operating revenues
Venezuela 547 570 1,451 2,281
Russia 167 138 1,929 452
United States and other 3,738 5,174 13,249 17,687
------------- ----------- ----------- ----------
Sub-total 4,452 5,882 16,629 20,420
Intersegment eliminations -United States (2,247) (2,033) (7,022) (7,232)
------------- ----------- ----------- ----------
Total other operating revenues 2,205 3,849 9,607 13,188
------------- ----------- ----------- ----------
Oil sales and other operating revenues
Venezuela 25,112 18,460 62,457 68,326
Russia 2,524 2,278 8,235 6,564
United States and other 3,738 5,174 13,249 17,687
------------- ----------- ----------- ----------
Sub-total 31,374 25,912 83,941 92,577
Intersegment eliminations -United States (2,247) (2,033) (7,022) (7,232)
------------- ----------- ----------- ----------
Total oil sales and other operating revenues $ 29,127 $ 23,879 $ 76,919 $ 85,345
============= =========== =========== ==========
OPERATING SEGMENT INCOME (LOSS)
Venezuela $ 4,802 $ (1,538) $ 2,080 $ (48,314)
Russia (266) (717) 459 (12,185)
United States and other (18,665) (5,584) (32,887) (18,369)
------------- ----------- ----------- ----------
Net Loss $ (14,129) $ (7,839) $ (30,348) $ (78,868)
============= =========== ====-====== ==========
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, SEPTEMBER 30,
1999 1998
--------------------------- ---------------------------
<S> <C> <C>
OPERATING SEGMENT ASSETS
Venezuela $108,634 $231,461
Russia 75,363 55,971
United States and other 217,614 270,995
-------------- ----------
Sub-total 401,611 558,427
Intersegment eliminations (101,364) (65,172)
-------------- -----------
Total Assets $300,247 $493,255
============== ===========
</TABLE>
<PAGE> 13
NOTE 6 - RUSSIAN OPERATIONS
The European Bank for Reconstruction and Development and International Moscow
Bank 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. GEOILBENT began borrowing under these facilities
in October 1997 and has borrowed a total of $28.8 million through June 30, 1999.
From July through September 1999, GEOILBENT borrowed an additional $17.3 million
($5.9 million to the Company) and during October 1999 borrowed another $2.4
million ($0.8 to the Company). The proceeds from the loans are being used by
GEOILBENT to develop the North Gubkinskoye and Prisklonovoye Fields in West
Siberia, Russia. Because the Company accounts for its investment in GEOILBENT
based on a fiscal year ending September 30, the borrowings from July through
October 1999 will be reflected in the Company's consolidated financial
statements in the quarters ending December 31, 1999 and March 31, 2000. At
September 30, 1999 and December 31, 1998, the Company's share of borrowings
under these agreements (as of June 30, 1999 and September 30, 1998 for
GEOILBENT) was $9.8 million and $6.5 million, respectively. Additionally, during
1998 a subsidiary of the Company recorded an account receivable for pipe it
purchased for $5.0 million and sold at cost to GEOILBENT for use in the
development of the field. The unpaid portion of the receivable ($2.5 million at
September 30, 1999) not eliminated in consolidation is included in accounts
receivable, joint interest and other. During 1996 and 1997, the Company incurred
$4.1 million in financing costs related to the establishment of the EBRD
financing, which are recorded in other assets and are subject to amortization
over the life of the facility. In 1998, under an agreement with EBRD,
GEOILBENT's board ratified an agreement to reimburse the Company for $2.6
million of such costs. However, due to GEOILBENT's need for oil and gas
investment and the declining prices for crude oil, in the second quarter of 1998
the Company agreed to defer payment of those reimbursements.
Excise, pipeline and other taxes (including a new oil export tariff introduced
in 1999) continue to be levied on all oil producers and certain exporters.
Although the Russian regulatory environment has become less volatile, the
Company is unable to predict the impact of taxes, duties and other burdens for
the future.
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 providing or arranging a $100 million credit
facility for the project, the terms of which have yet to be finalized, which is
expected to be disbursed over the initial two-year development phase. The
Company has received voting shares representing a 40% ownership in 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 September 30, 1999, the Company had loaned
$13.8 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 4.0% equity interest. In December 1998 and in
1999, the Company purchased shares representing an additional 17% equity
interest not subject to any sale or transfer restrictions. The Company owned a
total of 57% of voting shares of Arctic Gas as of September 30, 1999, of which
21% was 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. Certain
provisions of Russian corporate law would effectively require minority
shareholder consent in the making of new agreements between the Company and
Arctic Gas, or to the changing of any terms in any existing agreements between
the two partners such as the Cooperation Agreement and the Share Disposition
Agreement, including the conditions upon which the restrictions on the shares
could be removed.
NOTE 7 - VENEZUELA OPERATIONS
On July 31, 1992, the Company and its partner, Venezolana de Inversiones y
Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement
to reactivate and further develop three Venezuelan oil fields with Lagoven,
S.A., then one of three exploration and production affiliates of the national
oil company, Petroleos de Venezuela, S.A. ("PDVSA") which have subsequently all
been combined into PDVSA Petroleo y Gas, S.A. (all such parent, subsidiary and
affiliated entities hereinafter referred to as "PDVSA"). The operating service
agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South
Monagas Unit ("Unit"). Under the terms of the operating service agreement,
Benton-Vinccler, C.A. ("Benton-Vinccler"), a corporation owned 80% by the
Company and 20% by Vinccler, is a contractor for PDVSA and is responsible for
overall operations of the Unit, including all necessary investments to
reactivate and develop the fields comprising the Unit. Benton-Vinccler receives
an operating fee in U.S. dollars deposited into a U.S. commercial bank account
for each barrel of crude oil produced (subject to periodic adjustments to
reflect changes in a special energy index of the U.S. Consumer Price Index) and
is reimbursed according to a prescribed formula in U.S. dollars for its capital
costs, provided that such operating fee and cost recovery fee cannot exceed the
maximum dollar amount per barrel set
<PAGE> 14
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. Concurrent 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 is collateralized by a time deposit of the
Company. Permanent repayment of a portion of the loan allows the Company to
reduce the cash collateral for the loan thereby making such cash available for
working capital needs.
In November 1999, the Company entered into a letter of intent with Schlumberger
to further develop the South Monagas Unit pursuant to a long-term
incentive-based development program. Subject to execution of a definitive
agreement, Schlumberger has agreed to financial incentives intended to reduce
drilling costs 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 intends
to commence drilling with a one-rig program initially, with the possible
addition of a second rig in the middle of 2000.
In January 1996, the Company and its bidding partners, Louisiana Land &
Exploration, which has been subsequently acquired by Burlington Resources, Inc.
("Burlington"), and Norcen Energy Resources, LTD, which has been subsequently
acquired by Union Pacific Resources Group Inc. ("UPR"), were awarded the right
to explore and develop the Delta Centro Block in Venezuela. The contract
requires a minimum exploration work program consisting of completing an 839
kilometer seismic survey and drilling three wells to depths of 12,000 to 18,000
feet within five years. At the time the block was tendered for international
bidding, PDVSA estimated that this minimum exploration work program would cost
$60 million and required that the Company and the other partners each post a
performance surety bond or standby letter of credit for its pro rata share of
the estimated work commitment expenditures. The Company has a 30% interest in
the exploration venture, with Burlington and UPR each owning a 35% interest.
Under the terms of the operating agreement, which establishes the management
company of the project, Burlington will be the operator of the field and,
therefore, the Company will not be able to exercise control of the operations of
the venture. Corporacion Venezolana del Petroleo, S.A., an affiliate of PDVSA,
has the right to obtain a 35% interest in the management company, which dilutes
the voting power of the partners on a pro rata basis. In July 1996, formal
agreements were finalized and executed, and the Company posted an $18 million
standby letter of credit, collateralized in full by a time deposit of the
Company, to secure its 30% share of the minimum exploration work program (see
Note 3). During 1999, the first of the Block's exploration wells 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. As of September 30,
1999, the Company's share of expenditures related to the Block was $15.1
million, and its standby letter of credit had been reduced to $7.7 million.
NOTE 8 - CHINA OPERATIONS
In December 1996, the Company acquired Benton Offshore China Company, a
privately held corporation headquartered in Denver, Colorado, for 628,142 shares
of common stock and options to purchase 107,571 shares of the Company's common
stock at $7.00 per share, valued in total at $14.6 million. Benton Offshore
China Company's primary asset is a large undeveloped acreage position in the
South China Sea under a petroleum contract with China National Offshore Oil
Corporation ("CNOOC") of the People's Republic of China for an area known as
Wan'An Bei, WAB-21. Benton Offshore China Company will, as a wholly owned
subsidiary of the Company, continue as the operator and contractor of WAB-21.
Benton Offshore China Company has submitted an exploration program and budget to
CNOOC. However, due to certain territorial disputes over the sovereignty of the
contract area, it is unclear when such program will commence.
In October 1997, the Company signed a farmout agreement with Shell Exploration
(China) Limited ("Shell") whereby the Company acquired a 50% participation
interest in Shell's Liaohe area onshore exploration project in northeast China.
Shell holds a petroleum contract with China National Petroleum Corporation
("CNPC") to explore and develop the deep rights in the Qingshui Block, a 563
square kilometer area (approximately 140,000 acres) in the delta of the Liaohe
River. Shell is the operator of the project. In July 1998, the Company paid to
Shell 50% of Shell's prior investment in the Block, which was approximately $4
million ($2 million to the Company). 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 $12.7
million at September 30, 1999.
<PAGE> 15
NOTE 9 - SANTA BARBARA OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy Company, LLC
("Molino Energy"), which held 100% of these leases. The project area covers the
Molino, Gaviota and Caliente Fields, located approximately 35 miles west of
Santa Barbara, California. In consideration of the 40% participation interest in
the leases, the Company became the operator of the project and 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.
The Company's share of the drilling and testing of the 2199 #7 well was $9.0
million. In November 1998, the Company entered into an agreement to acquire
Molino Energy's interest in the leases in exchange for the release of the joint
interest billing obligations of approximately $1.9 million due from Molino
Energy. As of September 30, 1999, the Company continued to work with Molino
Energy to finalize the agreement to acquire Molino Energy's interest.
NOTE 10 - JORDAN OPERATIONS
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over approximately eight years. The Company
is obligated to spend $5.1 million in the first exploration phase, which has
been extended to May 2000. If the Company ultimately elects to continue through
phases two and three, it would be obligated to spend an additional $18 million
over the succeeding six years. During the first quarter of 1998, the Company
reentered two wells and tested two different reservoirs. The WS-9 and WS-10
wells did not result in the production of commercial amounts of hydrocarbons.
The Company will continue to reprocess and remap seismic data and conduct
geological studies on the remaining prospectivity of the block. As of September
30, 1999, the Company had incurred capital expenditures of $3.7 million related
to the PSA.
NOTE 11 - SENEGAL OPERATIONS
In December 1997, the Company signed a memorandum of understanding with Societe
des Petroles du Senegal ("Petrosen"), the state oil company of the Republic of
Senegal, to receive a minimum 45% working interest in and to operate the
approximately one million acre onshore Thies Block in western Senegal. The
Company's $5.4 million work commitment on the Thies Block, where Petrosen has
recently drilled and completed the Gadiaga #2 discovery well, consists of
hooking up the existing well, drilling two additional wells and constructing a
41-kilometer (approximately 25-mile) gas pipeline to Senegal's main electric
generating facility near Dakar. As of September 30, 1999, the Company had
incurred capital expenditures of $0.8 million related to the onshore block. The
Company is continuing to evaluate all of its alternatives associated with this
Block.
The Company also obtained exclusive rights from Petrosen to evaluate and
reprocess geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea-Bissau border in the south. The Company has
elected to not continue with the evaluation of, and has relinquished its
interest in, the near-offshore acreage and, accordingly, recognized a write-down
at June 30, 1999 of the capitalized costs related to the acreage of $1.2
million.
NOTE 12 - RELATED PARTY TRANSACTIONS
Prior to November 30, 1998 and during 1997 and 1996, the Company made unsecured
loans documented by a promissory note bearing interest at 6% to Mr. A. E.
Benton, its former Chief Executive Officer. At December 31,1997 and September
30, 1998, the balances owed to the Company were $2.0 million and $4.4 million,
respectively. In the fourth quarter of 1998, the Company loaned Mr. Benton an
additional $1.1 million to enable him to reduce and eliminate his outstanding
margin accounts with third parties that were secured by shares of the Company's
stock. The Company then obtained a security interest in those shares of stock,
certain personal real estate and proceeds from certain contractual and stock
option agreements. At December 31, 1998, the $5.5 million owed to the Company by
Mr. Benton, which is documented by a promissory note that bears interest at 6%
and is payable on November 30, 1999, exceeded the value of the collateral,
primarily due to the decline in the price of the Company's stock. As a result,
the Company recorded an allowance for doubtful accounts of $2.9 million. In
August 1999, Mr. Benton filed for Chapter 11 bankruptcy in Santa Barbara County,
California. Mr. Benton has not yet provided a reorganization plan for
consideration by the bankruptcy court or creditors. The bankruptcy filing has
changed the status of the collateral securing the loans, and the amount
eventually realized by the Company will depend on the results of the bankruptcy
proceedings. Accordingly, 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,
<PAGE> 16
1999 and continues to record additional allowances as interest accrues.
Measuring the amount of the allowance requires judgments and estimates, and the
amount eventually realized may differ from the estimate.
Also during 1997 and 1996, the Company made loans to Mr. M.B. Wray, its Vice
Chairman, and Mr. J.M. Whipkey, its Chief Financial Officer, each loan bearing
interest at 6% and collateralized by a security interest in personal real
estate. On May 11, 1999, Mr. Wray repaid the entire balance of principal and
interest on his loan. At September 30, 1999, the balance owed to the Company by
Mr. Whipkey was $0.4 million. At December 31, 1998, the balances owed to the
Company by Mr. Wray and Mr. Whipkey were $0.6 million and $0.5 million,
respectively.
In addition, receivables from other employees and directors of the Company
totaled $0.7 million and $0.6 million at September 30, 1999 and December 31,
1998, respectively.
<PAGE> 17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The Company cautions that any forward-looking statements (as such term is
defined in the Private Securities Litigation Reform Act of 1995) contained in
this report or made by management of the Company involve risks and uncertainties
and are subject to change based on various important factors. When used in this
report, the words budget, budgeted, anticipate, expect, believes, goals or
projects and similar expressions are intended to identify forward-looking
statements. In accordance with the provisions of the Private Securities
Litigation Reform Act of 1995, the Company cautions that important factors could
cause actual results to differ materially from those in the forward-looking
statements. Such factors include the 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, 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, and other risks
indicated in filings with the Securities and Exchange Commission. The following
factors, among others, in some cases have affected and could cause actual
results and plans for future periods to differ materially from those expressed
or implied in any such forward-looking statements: fluctuations in oil and gas
prices, changes in operating costs, overall economic conditions, political
stability, acts of terrorism, currency and exchange risks, changes in existing
or potential tariffs, duties or quotas, availability of additional exploration
and development opportunities, availability of sufficient financing, changes in
weather conditions, and ability to hire, retain and train management and
personnel.
GENERAL
PRINCIPLES OF CONSOLIDATION AND ACCOUNTING METHODS
The consolidated financial statements include the accounts of the Company and
its subsidiaries. The Company's investment in GEOILBENT, its Russian joint
venture, is accounted for using proportionate consolidation based on the
Company's ownership interest. The Company's investment in Arctic Gas, a Russian
open joint stock company, is accounted for using the equity method because of
the significant influence the Company exercises over its operations and
management. All intercompany profits, transactions and balances have been
eliminated. The Company accounts for its investment in GEOILBENT and Arctic Gas
based on a fiscal year ending September 30.
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all acquisition, exploration,
and development costs incurred. The Company accounts for its oil and gas
properties using cost centers on a country by country basis. Proceeds from sales
of oil and gas properties are credited to the full-cost pools. Capitalized costs
of oil and gas properties are amortized within the cost centers on an overall
unit-of-production method using proved oil and gas reserves as determined by
independent petroleum engineers. Costs amortized include all capitalized costs
(less accumulated amortization), the estimated future expenditures (based on
current costs) to be incurred in developing proved reserves, and estimated
dismantlement, restoration and abandonment costs. (See Note 1 of Notes to
Consolidated Financial Statements.)
The following discussion of the Company's results of operations for the nine
months ended September 30, 1999 and 1998 and financial condition at September
30, 1999 and December 31, 1998 should be read in conjunction with the Company's
Consolidated Financial Statements and related notes thereto included in PART I,
Item 1, "Financial Statements."
RESULTS OF OPERATIONS
The Company's results of operations for the nine months ended September 30,
1999, reflected the results for Benton-Vinccler, C.A. in Venezuela, which
accounted for more than 87% of the Company's production and oil sales revenue.
As a result of lower production from the South Monagas Unit due to lower capital
spending and continuing operational problems with certain high volume wells, oil
sales in Venezuela were 8% lower in the first nine months of 1999 compared to
1998 with a 22% decrease in oil sales quantities (from 9,496,143 Bbls of oil in
1998 to 7,397,614 Bbls of oil in 1999) substantially offset by an increase in
realized fees per barrel (from $6.95 in 1998 to $8.25 in 1999). Benton-Vinccler
also experienced increased operating expenses on a per barrel basis primarily
related to workovers and plant repairs and maintenance.
<PAGE> 18
The following table presents selected expense items from the Company's
consolidated income statement items as a percentage of oil and gas sales:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------------- ---------------------------
1999 1998 1999 1998
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Lease Operating Costs and Production Taxes 42.2% 53.0% 48.4% 49.0%
Depletion, Depreciation and Amortization 16.8 38.5 22.3 39.7
General and Administrative 20.0 26.2 28.9 23.1
Interest 27.2 41.2 33.9 33.8
</TABLE>
THREE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
The Company had revenues of $29.1 million for the three months ended September
30, 1999. Expenses incurred during the period consisted of lease operating costs
and production taxes of $11.4 million, depletion, depreciation and amortization
expense of $4.5 million, impairment of oil and gas properties of $13.0 million,
general and administrative expense of $5.4 million, interest expense of $7.3
million, income tax expense of $1.4 million and a minority interest of $0.2
million. Net loss was $14.1 million or $0.48 per share (diluted).
By comparison, the Company had revenues of $23.9 million for the three months
ended September 30, 1998. Expenses incurred during the period consisted of lease
operating costs and production taxes of $10.6 million, depletion, depreciation
and amortization expense of $7.7 million, general and administrative expense of
$5.2 million, interest expense of $8.2 million, income tax expense of $0.2
million and a minority interest reduction of $0.3 million. Net loss for the
period was $7.8 million or $0.27 per share (diluted).
Revenues increased $5.2 million, or 22%, during the three months ended September
30, 1999 compared to the corresponding period of 1998 primarily due to increased
oil sales revenue in Venezuela as a result of higher crude prices which were
partially offset by lower sales quantities and decreased investment earnings.
Sales quantities for the three months ended September 30, 1999 from Venezuela
and Russia were 2,296,866 Bbls and 355,532 Bbls, respectively, compared to
2,659,384 Bbls and 256,168 Bbls, respectively, for the three months ended
September 30, 1998. Prices for crude oil averaged $10.70 per Bbl (pursuant to
terms of an operating service agreement) from Venezuela and $6.63 per Bbl from
Russia for the three months ended September 30, 1999 compared to $6.73 per Bbl
from Venezuela and $8.35 per Bbl from Russia for the corresponding period of
1998. Investment earnings decreased $1.0 million, or 30%, during the three
months ended September 30, 1999 compared to the three months ended September 30,
1998 due to lower average cash and marketable securities balances. Revenues for
the three months ended September 30, 1999 were decreased by a foreign exchange
loss of $0.1 million compared to a gain of $0.5 million during the corresponding
period of 1998.
Lease operating costs and production taxes increased $0.8 million, or 8%, during
the three months ended September 30, 1999 compared to the three months ended
September 30, 1998 primarily due to increased workover costs in Venezuela
partially offset by reduced oil production in Venezuela and reduced costs in
Russia as a result of the devaluation of the ruble in 1998. Depletion,
depreciation and amortization decreased $3.2 million, or 42%, during the three
months ended September 30, 1999 compared to the corresponding period of 1998
primarily due to reduced oil sales quantities in Venezuela and write-downs of
oil and gas properties in Venezuela and Russia during 1998. Depletion expense
per barrel of oil equivalent produced from Venezuela and Russia during the three
months ended September 30, 1999 was $1.47 and $2.07, respectively, compared to
$2.46 and $3.27, respectively, during the corresponding period of the previous
year. As a result of the effect of declines in world crude oil prices, at June
30, 1998 the Company recognized a write-down of oil and gas properties in the
Venezuela and Russia cost centers of $38.4 million and $10.1 million,
respectively, pursuant to the ceiling limitation prescribed by the full cost
method of accounting. At September 30, 1999, the Company recognized write-downs
of $13.0 million of capitalized costs in China primarily related to unsuccessful
exploration activities on the Qingshui Block. The Company also recognized
write-downs of $5.5 million and $1.3 million at June 30, 1998 and 1999,
respectively, of capitalized costs associated with various other exploration
activities. General and administrative expenses increased $0.2 million, or 4%,
during the three months ended September 30, 1999 compared to the corresponding
period of 1998 primarily due to the costs of advisory services provided by J.P.
Morgan Securities, Inc., costs incurred in the Company's Russia, Delta Centro
and China operations and Venezuelan municipal taxes (which are a function of oil
revenues). Interest expense decreased $0.9 million, or 11%, during the three
months ended September 30, 1999 compared to the three months ended September 30,
1998 primarily due to the capitalization of interest expense. The Company
recognized a loss before income taxes and minority interest of $12.5 million
during the three months ended September 30, 1999 as compared to a loss of $7.9
million in the corresponding period of 1998, which resulted in increased income
tax expense of $1.2 million. The income attributable to the minority interest
increased $0.5 million for the three months ended September 30, 1999 compared to
the three months ended September 30, 1998 because the cumulative losses
attributable to the minority shareholder of Benton-Vinccler exceeded their
interest in equity capital creating an equity deficit. Income
<PAGE> 19
attributable to the minority shareholder will be included in the consolidated
results of the Company until the minority shareholder's equity deficit is
eliminated.
NINE MONTHS ENDED SEPTEMBER 30, 1998 AND 1997
The Company had revenues of $76.9 million for the nine months ended September
30, 1999. Expenses incurred during the period consisted of lease operating costs
and production taxes of $32.6 million, depletion, depreciation and amortization
expense of $15.0 million, impairment of oil and gas properties of $14.3 million,
general and administrative expense of $19.5 million, interest expense of $22.8
million, income tax expense of $2.5 million and a minority interest of $0.5
million. Net loss for the period was $30.3 million or $1.03 per share (diluted).
By comparison, the Company had revenues of $85.3 million for the nine months
ended September 30, 1998. Expenses incurred during the period consisted of lease
operating costs and production taxes of $35.4 million, depletion, depreciation
and amortization expense of $28.7 million, write-down and impairment of oil and
gas properties of $71.5 million, general and administrative expense of $16.7
million, interest expense of $24.4 million, income tax benefit of $7.8 million,
and minority interest reduction of $4.6 million. Net loss for the period was
$78.9 million or $2.67 per share (diluted).
Revenues decreased $8.4 million, or 10%, during the nine months ended September
30, 1999 compared to the corresponding period of 1998 primarily due to decreased
oil sales in Venezuela as a result of lower oil sales quantities which were
substantially offset by increased crude oil prices. Sales quantities for the
nine months ended September 30, 1999 from Venezuela and Russia were 7,397,614
Bbls and 1,070,799 Bbls, respectively, compared to 9,496,143 Bbls and 630,236
Bbls, respectively, for the nine months ended September 30, 1998. Prices for
crude oil averaged $8.25 per Bbl (pursuant to terms of an operating service
agreement) from Venezuela and $5.89 per Bbl from Russia for the nine months
ended September 30, 1999 compared to $6.95 per Bbl from Venezuela and $9.70 per
Bbl from Russia for the corresponding period of 1998. Investment earnings
decreased $4.0 million, or 36%, during the nine months ended September 30, 1999
compared to the nine months ended September 30, 1998 due to lower average cash
and marketable securities balances. Revenues for the nine months ended September
30, 1999 were increased by a foreign exchange gain of $2.4 million compared to a
gain of $2.0 million during the corresponding period of 1998.
Lease operating costs and production taxes decreased $2.8 million, or 8%, during
the nine months ended September 30, 1999 compared to the nine months ended
September 30, 1998 primarily due to reduced oil production in Venezuela and
reduced costs in Russia as a result of the devaluation of the ruble in 1998.
Depletion, depreciation and amortization decreased $13.7 million, or 48%, during
the nine months ended September 30, 1999 compared to the corresponding period of
1998 primarily due to reduced oil sales quantities in Venezuela and write-downs
of oil and gas properties in Venezuela and Russia during the nine months ended
September 30, 1998. Depletion expense per barrel of oil equivalent produced from
Venezuela and Russia during the nine months ended September 30, 1999 was $1.55
and $2.11, respectively, compared to $2.69, and $3.51 from Venezuela and Russia,
respectively, during the corresponding period of the previous year. As a result
of the effect of declines in world crude oil prices, at June 30, 1998, the
Company recognized write-downs of oil and gas properties in the Venezuela and
Russia cost centers of $55.9 million and $10.1 million, respectively, pursuant
to the ceiling limitation prescribed by the full cost method of accounting. At
September 30, 1999, the Company recognized write-downs of $13.0 million of
capitalized costs in China primarily related to unsuccessful exploration
activities on the Qingshui Block. The Company also recognized write-downs of
$5.5 million and $1.3 million at June 30, 1998 and 1999, respectively, of
capitalized costs associated with various other exploration activities. General
and administrative expenses increased $2.8 million, or 17%, during the nine
months ended September 30, 1999 compared to the corresponding period of 1998
primarily due to an allowance for doubtful accounts related to amounts owed to
the Company by its former Chief Executive Officer (see Note 12 of Notes to the
Consolidated Financial Statements), the costs of advisory services provided by
J.P. Morgan Securities, Inc. and costs incurred in the Company's Russia, Delta
Centro and China operations. Interest expense decreased $1.6 million, or 7%,
during the nine months ended September 30, 1999 compared to the nine months
ended September 30, 1998 primarily due to the capitalization of interest. The
Company recognized a loss before income taxes and minority interest of $27.3
million during the nine months ended September 30, 1999 as compared to a loss of
$91.2 million in the corresponding period of 1998 which resulted in increased
income tax expense of $10.3 million. The loss attributable to the minority
interest decreased $5.1 million for the nine months ended September 30, 1999
compared to the nine months ended September 30, 1998 because the cumulative
losses attributable to the minority shareholder of Benton-Vinccler exceeded
their interest in equity capital creating an equity deficit. Income attributable
to the minority shareholder will be included in the consolidated results of the
Company until the minority shareholder's equity deficit is eliminated.
<PAGE> 20
DOMESTIC OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy, which held 100%
of these leases. The project area covers the Molino, Gaviota and Caliente
Fields, located approximately 35 miles west of Santa Barbara, California. In
consideration of the 40% participation interest in the leases, the Company
became the operator of the project and 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. The Company's share of
the drilling and testing of the 2199 #7 well was $9.0 million. In November 1998,
the Company entered into an agreement to acquire Molino Energy's interest in the
leases in exchange for the release of the joint interest billing obligations of
approximately $1.9 million due from Molino Energy. As of September 30, 1999, the
Company continued to work with Molino Energy to finalize the agreement to
acquire Molino Energy's interest.
INTERNATIONAL OPERATIONS
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%. However, Benton-Vinccler reported significantly lower effective tax
rates for 1996 and 1998 due to the effect of the devaluation of the Bolivar
while Benton-Vinccler uses the U.S dollar as its functional currency, and
further in 1998 due to a deferred tax asset valuation allowance. The Company
cannot predict the timing or impact of future devaluations in Venezuela.
A 3-D seismic survey has been conducted over the southwestern portion of the
Delta Centro Block in Venezuela at a total cost to the Company of $6.9 million.
During 1999, the first of the Block's exploration wells 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 Company's operations
related to Delta Centro will be subject to oil and gas industry taxation, which
currently provides for royalties of 16.66% and income taxes of 67.7%. As of
September 30, 1999, the Company had incurred capital expenditures of $15.1
million related to the block.
GEOILBENT is subject to a statutory income tax rate of 35%. GEOILBENT has also
been subject to various other tax burdens, including an oil export tariff which
was terminated effective July 1, 1996. Excise, pipeline and other taxes
(including a new oil export tariff introduced in 1999) continue to be levied on
all oil producers and certain exporters. The Russian regulatory environment
continues to be volatile and the Company is unable to predict the impact of
taxes, duties and other burdens for the future.
In December 1996, the Company acquired Benton Offshore China Company, a
privately held company headquartered in Denver, Colorado. Benton Offshore China
Company's principal asset is a petroleum contract with 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 1.0 million acres under certain
circumstances, and lies within an area which is the subject of a territorial
dispute between the People's Republic of China and Vietnam. Vietnam has also
executed an agreement on a portion of the same offshore acreage with Conoco Inc.
The territorial dispute has existed for many years, and there has been limited
exploration and no development activity in the area under dispute. It is
uncertain when or how this dispute will be resolved, and under what terms the
various countries and parties to the agreements may participate in the
resolution, although certain proposed economic solutions currently under
discussion would result in the Company's interest being reduced. Benton Offshore
China Company has submitted plans and budgets to CNOOC for an initial seismic
program to survey the area. However, exploration activities will be subject to
resolution of such territorial dispute. The Company has recorded no proved
reserves attributable to this petroleum contract.
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's National Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over eight years. The Company is obligated to
spend $5.1 million in the first exploration phase, which has been extended to
May 2000. If the Company ultimately elects to continue through phases two and
three, it would be obligated to spend an additional $18 million over the
succeeding six years. As of September 30, 1999, the Company had incurred capital
expenditures of $3.7 million related to the PSA.
In October 1997, the Company signed a farmout agreement with Shell whereby the
Company acquired a 50% participation interest in Shell's Liaohe area onshore
exploration project in northeast China. Shell holds a petroleum contract with
China National Petroleum Corporation ("CNPC") to explore and develop the deep
rights in the Qingshui Block, a 563 square kilometer area (approximately 140,000
acres) in the delta of the Liaohe River. Shell is the operator of the project.
In July 1998, the Company paid to Shell 50% of Shell's prior investment in the
Block, which was approximately $4 million
<PAGE> 21
($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 $12.7 million at September 30, 1999.
In December 1997, the Company signed a memorandum of understanding with Petrosen
to receive a minimum 45% working interest in and to operate the approximately
1.0 million acre onshore Thies Block in western Senegal. The Company's $5.4
million work commitment on the Thies Block, where Petrosen has recently drilled
and completed the Gadiaga #2 discovery well, consists of hooking up the existing
well, drilling two additional wells and constructing a 41-kilometer
(approximately 25-mile) gas pipeline to Senegal's main electric generating
facility near Dakar. As of September 30, 1999, the Company had incurred capital
expenditures of $0.8 million related to the onshore block. The Company is
continuing to evaluate all of its alternatives associated with this Block. The
Company also obtained exclusive rights from Petrosen to evaluate and reprocess
geophysical data for Senegal's shallow near-offshore acreage, an area
encompassing approximately 7.5 million acres extending from the Mauritania
border in the north to the Guinea-Bissau border in the south. The Company has
elected to not continue with the evaluation of, and has relinquished its
interest in, the near-offshore acreage and, accordingly, has recognized a
write-down at June 30, 1999 of the capitalized costs related to the acreage of
$1.2 million.
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 providing or arranging a $100 million credit
facility for the project, the terms of which have yet to be finalized, which is
expected to be disbursed over the initial two-year development phase. The
Company has received voting shares representing a 40% ownership in 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 September 30, 1999, the Company had loaned
$13.8 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 4.0% equity interest. In December 1998 and in
1999, the Company purchased shares representing an additional 17% equity
interest not subject to any sale or transfer restrictions. The Company owned a
total of 57% of the voting shares of Arctic Gas as of September 30, 1999, of
which 21% was 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.
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 between the two partners
such as the Cooperation Agreement and the Share Disposition Agreement, including
the conditions upon which the restrictions on the shares could be removed.
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION
The Company's results of operations and cash flow are affected by changing oil
and gas prices. However, the Company's Venezuelan revenues are based on a fee
adjusted quarterly by the percentage change of a basket of crude oil prices
instead of by absolute dollar changes, which dampens both any upward and
downward effects of changing prices on the Company's Venezuelan revenues and
cash flows. If the price of oil and gas increases, there could be an increase in
the cost to the Company for drilling and related services because of increased
demand, as well as an increase in revenues. Fluctuations in oil and gas prices
may affect the Company's total planned development activities and capital
expenditure program.
There are presently no restrictions in either Venezuela or Russia that restrict
converting U.S. dollars into local currency. However, from June 1994 through
April 1996, Venezuela implemented exchange controls which significantly limited
the ability to convert local currency into U.S. dollars. Because payments made
to Benton-Vinccler are made in U.S. dollars into its United States bank account,
and Benton-Vinccler is not subject to regulations requiring the conversion or
repatriation of those dollars back into Venezuela, the exchange controls did not
have a material adverse effect on Benton-Vinccler or the Company. Currently,
there are no exchange controls in Venezuela or Russia that restrict conversion
of local currency into U.S. dollars.
Within the United States, inflation has had a minimal effect on the Company, but
it is potentially an important factor in results of operations in Venezuela and
Russia. With respect to Benton-Vinccler and GEOILBENT, substantially all of the
sources of funds, including the proceeds from oil sales, the Company's
contributions and credit financings, are denominated in U.S. dollars, while
local transactions in Venezuela and Russia are conducted in local currency. When
the
<PAGE> 22
rate of increase in the value of the dollar compared to the Venezuelan bolivar
or the Russian ruble is less than the rate of inflation in these countries, then
inflation could be expected to have an adverse effect on the Company.
During the nine months ended September 30, 1999, the Company realized net
foreign exchange gains, primarily as a result of the decline in the value of the
Venezuelan bolivar and the Russian ruble during periods when the Company's
Venezuela-related subsidiaries and GEOILBENT had substantial net monetary
liabilities denominated in bolivares and rubles. The Company's net foreign
exchange gains attributable to its Venezuelan and Russian operations during the
nine months ended September 30, 1999, were $0.9 million and $1.5 million,
respectively. However, there are many factors affecting foreign exchange rates
and resulting exchange gains and losses, many of which are beyond the control of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the U.S. dollar. It is not possible to predict the extent
to which the Company may be affected by future changes in exchange rates and
exchange controls.
The Company's operations are affected by political developments, laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and results.
CAPITAL RESOURCES AND LIQUIDITY
The oil and gas industry is a highly capital intensive business. The Company
requires capital principally to fund the following costs: (i) drilling and
completion costs of wells and the cost of production and transportation
facilities; (ii) geological, geophysical and seismic costs; and (iii)
acquisition of interests in oil and gas properties. The amount of available
capital will affect the scope of the Company's operations and the rate of its
growth.
The net funds raised and/or used in each of the operating, investing and
financing activities for the nine months ended September 30 are summarized in
the following table and discussed in further detail below (in thousands):
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------------------
1999 1998
------------- --------------
<S> <C> <C>
Net cash provided by operating activities $ 1,421 $ 17,853
Net cash provided by (used in) investing activities 16,658 (17,487)
Net cash provided by (used in) financing activities (12,846) 4,932
------------ -------------
Net increase in cash $ 5,233 $ 5,298
============ =============
</TABLE>
At September 30, 1999, the Company had current assets of $76.3 million and
current liabilities of $38.8 million resulting in working capital of $37.5
million and a current ratio of 2.0:1. This compares to the Company's working
capital of $55.9 million and a current ratio of 2.5:1 at December 31, 1998. The
decrease of $18.4 million was due primarily to expenditures related to
exploration and development in Venezuela, Russia and China.
CASH FLOW FROM OPERATING ACTIVITIES. During the nine months ended September 30,
1999 and 1998, net cash provided by operating activities was approximately $1.4
million and $17.9 million, respectively. Cash flow from operating activities
decreased by $16.5 million during the nine months ended September 30, 1999
compared to the corresponding period of the prior year due primarily to reduced
collections of accrued oil revenues. Collections of accrued oil revenues
decreased $38.1 million, or 39%, during the nine months ended September 30, 1999
compared to the corresponding period of 1998 due to lower production and prices
received from the South Monagas Field in Venezuela. Partially offsetting the
decrease in the collection of oil sale revenues was the change in the deferred
tax asset and other working capital items.
During 1999 the Company has focused on reducing general and administrative
expenses. Home office general and administrative cost reductions have offset
increased costs associated with advisory services provided by J.P. Morgan
Securities, Inc., costs incurred in the Company's Russia, Delta Centro and China
operations and increased Venezuelan municipal taxes (which are a function of oil
revenues). Additionally, in the fourth quarter of 1999 the Company reduced its
home office workforce by 23% and implemented a plan to further reduce other
general and administrative costs. As a result, the Company expects to realize a
$3 million reduction in home office general and administrative expenses in 2000.
CASH FLOW FROM INVESTING ACTIVITIES. During the nine months ended September 30,
1999 and 1998, the Company had drilling and production related capital
expenditures of approximately $32.6 million and $97.4 million, respectively. Of
the 1999 expenditures, $12.7 million was attributable to the development of the
South Monagas Unit in Venezuela, $2.1 million related to the development of the
North Gubkinskoye Field in Russia, $6.9 million related to a 3-D seismic survey
and exploratory well costs in the Delta Centro Block in Venezuela, $8.5 million
related to the development of the Qingshui Block
<PAGE> 23
in China, $1.1 million related to the Samburg Block in Russia (in addition to
$13.8 million loaned to Arctic Gas) and $1.3 million was attributable to other
projects. The capital expenditures during the nine months ended September 30,
1999 and 1998 were substantially offset by net redemptions of marketable
securities of $24.8 million and $85.3 million, respectively.
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. This policy was instituted in response
to the low market price for oil. In the second half of 1999, oil prices
recovered substantially, and the Company concluded a project to assess its
strategic alternatives. On November 10, 1999, the Company announced that it has
entered into a letter of intent with Schlumberger to form a long term
incentive-based alliance as part of its plans to further develop its oil
properties in the South Monagas Unit in Venezuela. Subject to execution of a
definitive agreement, Schlumberger has agreed to financial incentives intended
to reduce drilling costs 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.
The Company expects capital expenditures of approximately $40 million in 1999
and $55 million in 2000. Of the 1999 and 2000 capital expenditures, $14-16
million and $40-45 million, respectively, are related to the South Monagas Unit
in Venezuela. The 2000 capital expenditures at the South Monagas Unit will be
incurred in conjunction with an incentive-based development program with
Schlumberger. Also included in the capital expenditures are $4-5 million in 1999
and $6-7 million in 2000 by GEOILBENT in Russia, net to the Company's interest,
funding for which is expected to come from borrowings under the EBRD Credit
Facility, cash flow from operations or other financings.
Included in the 2000 capital expenditures for Arctic Gas Company is a budget of
$2 million to reactivate two existing wells and to produce and market oil and
gas condensate liquids on a pilot basis. The Company has also agreed to provide
or arrange loans of up to $100 million to Arctic Gas Company pursuant to an
equity acquisition agreement signed in April 1998, of which $13.8 million had
been loaned as of September 30, 1999 and $2 million will be loaned in 2000 to
fund the two-well reactivation project. The Company is currently evaluating
funding alternatives for the balance of the loans to Arctic Gas. As the Company
is the majority shareholder of Arctic Gas, the timing and size of the 1999-2000
capital investments for Arctic Gas are substantially at the Company's
discretion.
The Company's remaining capital commitments worldwide are relatively minimal and
for the most part are substantially at the Company's discretion. The Company's
indentures contain provisions that restrict the manner in which the Company can
invest in certain of its current operations.
The Company believes it has or can obtain sufficient funding for its expected
capital requirements for the remainder of 1999 and in 2000 from working capital
and cash flow from operations. However, the Company's future financial condition
and results of operations will largely depend upon prices received for its oil
production and the costs of acquiring, finding, developing and producing
reserves. Prices for oil are subject to fluctuations in response to changes in
supply, market uncertainty and a variety of factors beyond the Company's
control. However, since oil prices are currently at their highest levels in the
past twelve months, the Company is currently evaluating opportunities to hedge a
portion of its production for the year 2000.
The Company has total annual interest payments of approximately $25.3 million
related to its senior unsecured notes (see Note 2 of Notes to Consolidated
Financial Statements). If oil price realizations continue at or near current
levels, and if oil production continues at expected levels, the Company believes
that its current cash and cash provided by operating activities will be
sufficient to meet the Company's liquidity needs for routine operations and to
service its outstanding debt through November 2000. If oil prices and production
volumes later in 1999 and in 2000 result in cash flows that are less than
currently planned, then the Company may have to reduce further its planned
capital and operating expenditures in 2000, which could have negative effects on
future oil production rates.
The Company's oil and gas properties are still under development and will
require substantial investments in the future. In addition, the Company's
indebtedness includes senior unsecured notes due in 2003 ($125 million) and 2007
($105 million). The Company announced in November 1999 that it had concluded its
engagement with J.P. Morgan to evaluate the Company's strategic options and
alternatives. As announced in February 1999, the Company retained J.P. Morgan
Securities Inc. to act as its exclusive financial advisor to assist it in
initiating, evaluating and negotiating potential shareholder value maximizing
transactions. After careful consideration, the Board of Directors has decided to
pursue a strategic alliance with Schlumberger to further develop the South
Monagas Unit. This decision was based on the recent positive changes in the
industry climate, in particular the increase in oil prices over the last few
months. The Company believes that retaining its current equity positions in its
operations worldwide and applying its development skills to them is in the best
interests of the Company and its shareholders. In the event that the Company's
future cash requirements become greater than its financial resources, the
Company intends to pursue one or more of the following alternatives: reduce its
capital, operating and administrative expenditures, form strategic joint
ventures or alliances with other industry partners, sell property interests,
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.
<PAGE> 24
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. The indenture agreements provide for certain limitations on liens,
additional indebtedness, certain investment and capital expenditures, dividends,
mergers and sales of assets. At September 30, 1999, the Company was in
compliance with all covenants of the indentures.
The EBRD and IMB have agreed to lend a total of $65 million to GEOILBENT (owned
34% by the Company) under parallel reserve-based, non-recourse loan agreements.
GEOILBENT began borrowing under these facilities in October 1997 and, to date,
has borrowed $48.5 million. The proceeds from the loans are being used by
GEOILBENT to develop the North Gubkinskoye and Prisklonovoye fields in West
Siberia, Russia. Additional borrowings will be based on achieving certain
reserve and production milestones.
YEAR 2000 COMPLIANCE
The Year 2000 problem concerns the inability of information systems to properly
recognize and process date-sensitive information beyond January 1, 2000. The
Company began a process of assessing its information technology systems in
November 1997 and has to date not uncovered any significant Year 2000
deficiencies. Substantially all of the software utilized by the Company is
purchased or licensed from external providers. The accounting software used at
the Company's home office was upgraded in 1998 with a year 2000 compliance
modification provided by the software provider at minimal cost. The Company's
Venezuelan and Russian subsidiaries have been installing new accounting software
as a part of a process improvement initiative begun in 1997. The software
programs selected for installation at each location are Year 2000 compliant. The
Company's Venezuelan subsidiary has completed the accounting software
installation. The Russian subsidiaries are in the process of installing and
testing their accounting software programs but have fallen behind schedule and
do not anticipate completion before the end of 1999. The Russian subsidiaries'
new accounting software programs are not considered to be "mission critical",
however, in that all accounting processes can continue beyond the end of 1999
with Year 2000 compliant office business systems currently in use. All "mission
critical" office business systems are now Year 2000 compliant. A review of the
Company's non-financial software and imbedded chip technology to assess the
impact of the Year 2000 on systems such as plant flow control devices, product
measurement and delivery devices and fire or other disaster-related safety
systems was completed in the third quarter of 1999. All necessary testing and
remediation has taken place. To date, only minor Year 2000 modifications have
been required on these devices and the costs associated with modifications have
not exceeded $100,000. The Company does not anticipate that the cost of
converting any non-compliant systems will be material to its financial
condition.
The Company is in the process of finalizing contingency and recovery plans
related to "mission critical" systems. The contingency plans may include
changing suppliers and customers to those who have demonstrated Year 2000
readiness. However, there can be no assurance that the Company will be
successful in finding such alternative suppliers and customers. The oil produced
in Venezuela by the Company, which is delivered to PDVSA under the terms of an
operating service agreement in effect through 2012, represented approximately
91% of the Company's oil sales during 1998 and the nine months ended September
30, 1999. PDVSA has reported that their mission critical systems are essentially
ready for the Year 2000. However, in the event that PDVSA is unable to accept
deliveries of, or make payment for, the oil produced by the Company due to a
Year 2000 failure, the Company's operations and financial position could be
materially and adversely affected.
The failure to correct a material Year 2000 problem could result in an
interruption in, or a failure of, certain normal business activities or
operations. Such failures could materially and adversely affect the Company's
results of operations, liquidity and financial condition. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from the
uncertainty of the Year 2000 readiness of third-party suppliers and customers,
the Company is unable to determine at this time whether the consequences of Year
2000 failures will have a material impact on the Company's results of
operations, liquidity or financial condition.
<PAGE> 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 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. Average realizations per barrel have
varied in recent years from $10.07 in 1997 to as low as $6.01 in the first
quarter of 1999. 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. The
Company has considered such transactions from time to time as an element of its
risk management strategy, but as of September 30, 1999 has entered into no
further hedging transactions. However, since oil prices are currently at their
highest levels in the past twelve months, the Company is currently evaluating
opportunities to hedge a portion of its production for the year 2000. 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 and gas revenues when
the hedged production is delivered, such gains and losses are generally offset
by similar changes in the realized prices of the commodities.
INTEREST RATES
Total long term debt of $275.7 million at September 30, 1999, included $230
million of fixed-rate senior unsecured notes maturing in 2003 ($125 million) and
2007 ($105 million). Another $35.9 million of debt is attributable to
floating-rate back-to-back loan facilities wherein Benton-Vinccler and GEOILBENT
pay 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 0.375% for
Benton-Vinccler and less 0.25% for GEOILBENT, thereby mitigating the
floating-rate interest rate risk of such debt. The balance of $9.8 million (4%
of total long term debt), consisting primarily of the Company's share of debt
owed by Geoilbent, is subject to the market volatility of floating rates. 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 nine months ended
September 30, 1999.
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, revenues 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, revenues are received
primarily in US dollars, with less than 15% of such revenues being received in
local currency; 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
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
On September 1, 1999, the Company filed a report on Form 8-K,
under Item 5, "Other Events" regarding the Company's press
release related to the creation of the Office of the Chief
Executive and the resignation of A.E. Benton from his
positions as Chairman, Chief Executive Officer and President.
<PAGE> 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: November 12, 1999 By: /S/Michael B. Wray
-------------------------------
Michael B. Wray
Acting Chief Executive Officer
Dated: November 12, 1999 By: /S/James M. Whipkey
-------------------------------
James M. Whipkey
Senior Vice President and
Chief Financial Officer
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
FORM 10-Q FOR THE PERIOD ENDED SEPTEMBER 30, 1999 AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<EXCHANGE-RATE> 1
<CASH> 23,380
<SECURITIES> 16,334
<RECEIVABLES> 24,881
<ALLOWANCES> 6,104
<INVENTORY> 0
<CURRENT-ASSETS> 76,349
<PP&E> 510,186
<DEPRECIATION> 368,462
<TOTAL-ASSETS> 300,247
<CURRENT-LIABILITIES> 38,791
<BONDS> 275,713
0
0
<COMMON> 296
<OTHER-SE> (15,560)
<TOTAL-LIABILITY-AND-EQUITY> 300,247
<SALES> 67,312
<TOTAL-REVENUES> 76,919
<CGS> 47,616
<TOTAL-COSTS> 47,616
<OTHER-EXPENSES> 0
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<INTEREST-EXPENSE> 22,841
<INCOME-PRETAX> (27,317)
<INCOME-TAX> 2,499
<INCOME-CONTINUING> (30,348)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (30,348)
<EPS-BASIC> (1.03)
<EPS-DILUTED> (1.03)
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