<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 June 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
incorporation or organization) Identification Number)
6267 CARPINTERIA AVE., SUITE 200
CARPINTERIA, CALIFORNIA 93013
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (805) 566-5600
----------
Indicate by check mark whether the Registrant (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90
days.
Yes X No
--- ---
----------
At August 13, 1999, 29,576,966 shares of the
Registrant's Common Stock were outstanding.
<PAGE> 2
2
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets at June 30, 1999
and December 31, 1998 (Unaudited).....................................................3
Consolidated Statements of Operations for the Three
Months Ended June 30, 1999 and 1998 (Unaudited).......................................4
Consolidated Statements of Operations for the Six
Months Ended June 30, 1999 and 1998 (Unaudited) ......................................5
Consolidated Statements of Cash Flows for the Six
Months Ended June 30, 1999 and 1998 (Unaudited).......................................6
Notes to Consolidated Financial Statements.................................................8
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS..............................................................19
Item 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.......................................26
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS................................................................................28
Item 2. CHANGES IN SECURITIES............................................................................28
Item 3. DEFAULTS UPON SENIOR SECURITIES..................................................................28
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............................................28
Item 5. OTHER INFORMATION................................................................................28
Item 6. EXHIBITS AND REPORTS ON FORM 8-K.................................................................28
Signatures...............................................................................................................29
</TABLE>
<PAGE> 3
3
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, unaudited)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
--------- ---------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents $ 18,606 $ 18,147
Restricted cash 12 12
Marketable securities 5,827 41,173
Accounts, and notes receivable:
Accrued oil and gas revenue 20,743 17,307
Joint interest and other, net 8,760 12,482
Prepaid expenses and other 3,295 3,688
--------- ---------
TOTAL CURRENT ASSETS 57,243 92,809
RESTRICTED CASH 65,798 65,670
OTHER ASSETS 11,171 11,725
DEFERRED INCOME TAXES 3,357 2,976
INVESTMENT IN AND ADVANCES TO AFFILIATED COMPANY 20,202 11,975
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of $43,597 and
$35,228 excluded from amortization in 1999 and 1998, respectively) 509,828 483,494
Furniture and fixtures 9,489 9,608
--------- ---------
519,317 493,102
Accumulated depletion, impairment and depreciation (350,947) (339,636)
--------- ---------
168,370 153,466
--------- ---------
$ 326,141 338,621
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other $ 9,369 $ 10,014
Accrued interest payable 5,503 5,527
Accrued expenses 18,993 19,342
Income taxes payable 2,149 1,847
Current portion of long term debt 59 215
--------- ---------
TOTAL CURRENT LIABILITIES 36,073 36,945
LONG TERM DEBT 290,373 288,212
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST 830 475
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 June 30, 1999 and December 31, 1998 296 296
Additional paid-in capital 147,056 147,054
Retained deficit (147,788) (131,569)
Treasury stock, at cost, 50 shares (699) (699)
Employee note receivable, net -- (2,093)
--------- ---------
TOTAL STOCKHOLDERS' EQUITY (1,135) 12,989
--------- ---------
$ 326,141 $ 338,621
========= =========
</TABLE>
See notes to consolidated financial statements.
<PAGE> 4
4
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data, unaudited)
<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30,
---------------------------
1999 1998
------- --------
<S> <C> <C>
REVENUES
Oil sales $22,419 $ 23,626
Gain on exchange rates 1,140 886
Investment earnings and other 2,193 3,696
------- --------
25,752 28,208
------- --------
EXPENSES
Lease operating costs and production taxes 10,109 11,501
Depletion, depreciation and amortization 5,128 9,879
Write-down and impairment of oil and gas properties 1,275 53,967
General and administrative 8,498 6,046
Interest 7,685 8,030
------- --------
32,695 89,423
------- --------
LOSS BEFORE INCOME TAXES
AND MINORITY INTEREST (6,943) (61,215)
INCOME TAX EXPENSE (BENEFIT) 413 (7,294)
------- --------
LOSS BEFORE MINORITY INTEREST (7,356) (53,921)
MINORITY INTEREST 200 (3,878)
------- --------
NET LOSS $(7,556) $(50,043)
======= ========
NET LOSS PER COMMON SHARE:
Basic $ (0.26) $ (1.69)
======= ========
Diluted $ (0.26) $ (1.69)
======= ========
</TABLE>
See notes to consolidated financial statements.
<PAGE> 5
5
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data, unaudited)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
------------------------------
1999 1998
--------- ---------
<S> <C> <C>
REVENUES
Oil sales $ 40,390 $ 52,127
Gain on exchange rates 2,555 1,499
Investment earnings and other 4,847 7,840
--------- ---------
47,792 61,466
--------- ---------
EXPENSES
Lease operating costs and production taxes 21,240 24,742
Depletion, depreciation and amortization 10,495 20,945
Write-down and impairment of oil and gas properties 1,275 71,467
General and administrative 14,065 11,452
Interest 15,528 16,110
--------- ---------
62,603 144,716
--------- ---------
LOSS BEFORE INCOME TAXES AND MINORITY INTEREST (14,811) (83,250)
INCOME TAX EXPENSE (BENEFIT) 1,053 (7,964)
--------- ---------
LOSS BEFORE MINORITY INTEREST (15,864) (75,286)
MINORITY INTEREST 355 (4,257)
--------- ---------
NET LOSS $ (16,219) $ (71,029)
========= =========
LOSS PER COMMON SHARE:
Basic $ (0.55) $ (2.41)
========= =========
Diluted $ (0.55) $ (2.41)
========= =========
</TABLE>
See notes to consolidated financial statements.
<PAGE> 6
6
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands, unaudited)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
-----------------------------
1999 1998
-------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
$(16,219) $(71,029)
Net Loss
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization 10,495 20,945
Write-down of oil and gas properties 1,275 71,467
Amortization of financing costs 786 612
Loss on disposition of assets 38 --
Allowance for employee notes and accounts receivable 2,785
Minority interest in undistributed earnings of subsidiary 355 (4,257)
Deferred income taxes (381) (11,176)
Changes in operating assets and liabilities:
Accounts receivable (406) 16,633
Prepaid expenses and other 70 (4,468)
Accounts payable (645) (10,649)
Accrued interest payable (24) 21
Accrued expenses (349) 6,355
Income taxes payable 625 (1,427)
-------- --------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES (1,595) 13,027
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment (26,656) (70,211)
Investment in and advances to affiliated company (8,227) (2,376)
Increase in restricted cash (128) (78)
Purchase of marketable securities (12,048) (43,190)
Maturities of marketable securities 47,394 109,101
-------- --------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 335 (6,754)
-------- --------
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 2,897 4,802
Payments on short term borrowings and notes payable (892) (65)
Increase in other assets (288) (1,095)
-------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES 1,719 4,437
-------- --------
NET INCREASE IN CASH AND CASH EQUIVALENTS 459 10,710
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 18,147 11,940
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 18,606 $ 22,650
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for interest expense $ 15,623 $ 15,251
======== ========
Cash paid during the period for income taxes $ 670 $ 3,109
======== ========
</TABLE>
(continued)
See notes to consolidated financial statements.
<PAGE> 7
7
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the six months ended June 30 1999, the Company recorded an allowance for
doubtful accounts related to amounts owed to the Company by its 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 six months
ended June 30, 1998, the Company recorded these costs as an account receivable
from GEOILBENT.
See notes to consolidated financial statements.
<PAGE> 8
8
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
SIX MONTHS ENDED JUNE 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.
During 1998, the Company instituted a capital expenditure program which
minimized expenditures to those that the Company believed were necessary in
order to maintain current producing properties.
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuation in response to change in supply, market uncertainty and a variety of
factors beyond the Company's control.
The Company believes its current cash and cash to be provided by operating
activities will be sufficient to meet the Company's liquidity needs for routine
operations and to service its outstanding debt through 1999. The Company
continues to evaluate and review strategic alternatives and has engaged J.P.
Morgan Securities, Inc. to advise the Company related to these alternatives. If
future cash requirements are greater than the Company's financial resources, the
Company intends to pursue strategic joint ventures or alliances with other
industry partners, sell property interests, merge or combine with another
entity, or issue debt or equity securities. There can be no assurance that any
such transaction would 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 June 30,
1999, and the results of operations for the three and six month periods ended
June 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 six month periods ended June 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> 9
9
ACCOUNTS AND NOTES RECEIVABLE
The Company's allowance for doubtful accounts related to employee notes and
accounts receivable and other accounts receivable was $6.0 million at June 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, during the six month period ended June 30, 1999, losses attributable to
the minority shareholder of Benton-Vinccler, a subsidiary owned 80% by the
Company, exceeded its interest in equity capital. Accordingly, all of
Benton-Vinccler's loss for the six month period attributable to the minority
shareholders ($0.6 million) has been included in the consolidated net loss of
the Company.
MARKETABLE SECURITIES
Marketable securities are carried at amortized cost. The marketable securities
the Company may purchase are limited to those defined as Cash Equivalents in the
indentures for its senior unsecured notes. Cash Equivalents may be comprised of
high-grade debt instruments, demand or time deposits, bankers' acceptances and
certificates of deposit or acceptances of large U.S. financial institutions and
commercial paper of highly rated U.S. corporations, all having maturities of no
more than 180 days. The Company's marketable securities at cost, which
approximates fair value, consisted of $5.8 million and $41.2 million in
commercial paper at June 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 six month periods ended June 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 JUNE 30, 1999
----------------------------------------
BASIC EPS
Loss attributable to common stockholders $(7,556) 29,577 $(0.26)
======== ======== ========
DILUTED EPS
Loss attributable to common stockholders $(7,556) 29,577 $(0.26)
======== ======== ========
FOR THE THREE MONTHS ENDED JUNE 30, 1998
----------------------------------------
BASIC EPS
Loss attributable to common stockholders $(50,043) 29,565 $(1.69)
======== ======== ========
DILUTED EPS
Loss attributable to common stockholders $(50,043) 29,565 $(1.69)
======== ======== ========
</TABLE>
<PAGE> 10
10
<TABLE>
<CAPTION>
AMOUNT PER
LOSS SHARES SHARE
------------- ------------ ------------
<S> <C> <C> <C>
FOR THE SIX MONTHS ENDED JUNE 30, 1999
--------------------------------------
BASIC EPS
Loss attributable to common stockholders $(16,219) 29,577 $(0.55)
======== ======== ========
DILUTED EPS
Loss attributable to common stockholders $(16,219) 29,577 $(0.55)
======== ======== ========
FOR THE SIX MONTHS ENDED JUNE 30, 1998
--------------------------------------
BASIC EPS
Loss attributable to common stockholders $(71,029) 29,531 $(2.41)
======== ======== ========
DILUTED EPS
Loss attributable to common stockholders $(71,029) 29,531 $(2.41)
======== ======== ========
</TABLE>
An aggregate of 6.1 million and 4.8 million options and warrants were excluded
from the earnings per share calculations because they were anti-dilutive for the
three months ended June 30, 1999 and 1998, respectively. An aggregate of 6.0
million and 4.8 million options and warrants, were excluded from the earnings
per share calculations because they were anti-dilutive for the six months ended
June 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 $1.1 million and $1.2 million for the six months ended
June 30, 1999 and 1998, respectively, and capitalized interest of $1.0 million
for the six months ended June 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 a
write-down of oil and gas properties in the Venezuela cost center of $17.5
million at March 31, 1998, and recognized write-downs of oil and gas properties
in the Venezuela and Russia cost centers of $38.4 million and $10.1 million,
respectively, at June 30, 1998. Additionally, the Company recognized a
write-down of $5.5 million at June 30, 1998 and $1.3 million at June 30, 1999 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 June 30, 1999 were $5.0 million, $28.7 million, and $9.9 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 six months ended June 30, 1999 was $8.1 million and $1.5 million
($1.58 and $2.12 per equivalent barrel), respectively. Depletion expense
attributable to the Venezuela and Russia cost centers for the six months ended
June 30,1998 was $19.0 million and $1.4 million ($2.78 and $3.68 per equivalent
barrel), respectively. Depreciation of furniture and fixtures is computed using
the straight-line method, with depreciation rates based upon the estimated
useful life applied to the cost of each class of property. Depreciation expense
was $0.8 million and $0.6 million for the six months ended June 30, 1999 and
1998, respectively.
RECLASSIFICATIONS
Certain items in 1998 have been reclassified to conform to the 1999 financial
statement presentation.
<PAGE> 11
11
NOTE 2 - LONG TERM DEBT
Long term debt consists of the following (in thousands):
<TABLE>
<CAPTION>
JUNE 30, 1999 DECEMBER 31, 1998
------------- -----------------
<S> <C> <C>
Senior unsecured notes with interest at 9.375%
See description below $105,000 $105,000
Senior unsecured notes with interest at 11.625%
See description below 125,000 125,000
Benton-Vinccler credit facility with interest at
LIBOR plus 6.125%. Collateralized by a time deposit of the Company
earning approximately LIBOR plus 5.75%
See description below 50,000 50,000
Reserve-based loans with average interest
rate of LIBOR plus 5.25%. See description below 9,286 6,453
GEOILBENT credit facility collateralized by a time deposit of the
Company earning approximately 5.6%. See description below 974 1,624
Other 172 350
-------- --------
290,432 288,427
Less current portion 59 215
-------- --------
$290,373 $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 June 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. 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 June 30, 1999, GEOILBENT (owned 34% by the Company) has borrowed $27.3
million under parallel reserve-based loan agreements with the European Bank for
Reconstruction and Development ("EBRD") and International Moscow Bank ("IMB").
EBRD and IMB have agreed to lend up to a total of $65 million to GEOILBENT based
on achieving certain reserve and production milestones. Under these loan
agreements, the Company and other shareholders of GEOILBENT have significant
management and business support obligations. Each shareholder is jointly and
severally liable to EBRD and IMB for any losses, damages, liabilities, costs,
expenses and other amounts suffered or sustained arising out of any breach by
any shareholder of its support obligations. The loans bear an average interest
rate of LIBOR plus 5.25% payable on January 27 and July 27 each year. Principal
payments will be due in varying installments every six months beginning January
27, 2000 until July 27, 2004. The loan agreements require that GEOILBENT meet
certain financial ratios and covenants, including a minimum current ratio, and
provides for certain limitations on liens, additional indebtedness, certain
investment and capital expenditures, dividends, mergers and sales of assets. The
Company's share of the amounts borrowed under the loan agreements was $9.3
million and $6.5 million at June 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 six months ended June
30, 1999, EBRD and IMB consented to the repayment of $2.0 million ($0.7 million
to the Company) in exchange for the Company's capital contribution to GEOILBENT
of $2.0 million. The credit facility contains no restrictive covenants and no
financial ratio covenants.
<PAGE> 12
12
NOTE 3 - COMMITMENTS AND CONTINGENCIES
On February 17, 1998, the WRT Creditors Liquidation Trust filed suit in the
United States Bankruptcy Court, Western District of Louisiana against the
Company and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil & Gas
of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to Tesla
Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties and that it paid a
price in excess of the fair value of the property. A trial date has been
scheduled for October 25, 1999 and discovery is ongoing, but incomplete. The
Company intends to vigorously contest the suit, and in management's opinion it
is too early to assess the probability of an unfavorable outcome.
In the normal course of its business, the Company may periodically become
subject to actions threatened or brought by its investors or partners in
connection with the operation or development of its properties or the sale of
securities. The Company is also subject to ordinary litigation that is
incidental to its business, none of which are expected to have a material
adverse effect on the Company's financial statements.
In May 1996, the Company entered into an agreement with Morgan Guaranty which
provided for an $18 million cash collateralized 5-year letter of credit to
secure the Company's performance of the minimum exploration work program
required in the Delta Centro Block in Venezuela. In December 1998, the letter of
credit was reduced to $11.2 million as a result of expenditures made related to
the exploration work program. 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 July 10, 1999 to June 1, 2001. The
Company has also entered into employment agreements with eight individuals,
which provide for certain severance payments in the event of a change of control
of the Company and subsequent termination by the employees for good reason.
The Company has entered into various exploration and development contracts in
various countries which require minimum expenditures, some of which required
that the Company secure its commitments by providing letters of credit. The
Company has also entered into equity acquisition agreements in Russia which call
for the Company to provide or arrange for certain amounts of credit financing in
order to remove sale and transfer restrictions on the equity acquired or to
maintain ownership in such equity.
In 1998, the Company entered into a 15-year lease agreement for office space in
Carpinteria, California. The Company has leased 50,000 square feet for
approximately $74,000 per month with annual rent adjustments based on certain
changes in the Consumer Price Index. The Company has entered into a sublease
agreement for a portion of the office space which is not currently needed for
operations. The Company has also entered into a sublease agreement for the
office space that it previously occupied. Rents for the subleases approximate
the Company's lease costs of these facilities.
NOTE 4 - TAXES ON INCOME
At December 31, 1998, the Company had, for federal income tax purposes,
operating loss carryforwards of approximately $90 million expiring in the years
2003 through 2018. If the carryforwards are ultimately realized, approximately
$13 million will be credited to additional paid-in capital for tax benefits
associated with deductions for income tax purposes related to stock options.
During the six months ended June 30, 1999, the Company recorded deferred tax
assets generated from current period operating losses and a valuation allowance
of $5.2 million.
The Company does not provide deferred income taxes on undistributed earnings of
international consolidated subsidiaries for possible future remittances as all
such earnings are reinvested as part of the Company's ongoing business.
NOTE 5 - OPERATING SEGMENTS
The Company regularly allocates resources to and assesses the performance of its
operations by segments that are organized by unique geographic and operating
characteristics. The segments are organized in order to manage regional
business, currency and tax related risks and opportunities. Revenues from the
Venezuela and Russia operating segments are derived primarily from the
production and sale of oil. Revenues from USA and Other are derived primarily
from interest earnings on various investments and consulting revenues.
Operations included under the heading "USA and Other"
<PAGE> 13
13
include corporate management, exploration activities, cash management and
financing activities performed in the United States and other countries which do
not meet the requirements for separate disclosure. All intersegment revenues,
expenses and receivables are eliminated in order to reconcile to consolidated
totals. Corporate general and administrative and interest expenses are included
in the USA and Other segment and are not allocated to other operating segments.
The Company's investment in Arctic Gas has been included in the Russia operating
segment.
<TABLE>
<CAPTION>
INTER-
THREE MONTHS ENDED USA AND SEGMENT
JUNE 30, 1999 (IN THOUSANDS) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- ---------------------------- --------- ------ ----- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenue:
Oil sales $20,352 $2,067 $22,419
Net gain on exchange rates 370 600 $ 170 1,140
Investment earnings and other 156 (81) 2,424 $ (306) 2,193
Intersegment revenues -- -- 2,578 (2,578) --
------- ------ ------- ------- -------
Total revenues 20,878 2,586 5,172 (2,884) 25,752
------- ------ ------- ------- -------
Expenses:
Lease operating costs and production
taxes 9,705 1,098 (151) (543) 10,109
Depletion, depreciation and
amortization 4,117 821 190 -- 5,128
General and administrative 1,509 501 6,488 -- 8,498
Interest 1,811 318 5,862 (306) 7,685
Intersegment expenses 2,035 -- -- (2,035) --
------- ------ ------- ------- -------
Total expenses 19,177 2,738 12,389 (2,884) 31,420
------- ------ ------- ------- -------
Income (loss) before income taxes 1,701 (152) (7,217) -- (5,668)
Income tax expense 363 7 43 -- 413
------- ------ ------- ------- -------
Operating segment income (loss) 1,338 (159) (7,260) -- (6,081)
Write-down and impairment of oil and
gas properties -- -- (1,275) -- (1,275)
Minority interest (200) -- -- -- (200)
------- ------ ------- ------- -------
Net income (loss) $ 1,138 $ (159) $(8,535) -- $(7,556)
======= ====== ======= ======= =======
Capital expenditures $ 4,884 $1,176 $ 4,690 -- $10,750
======= ====== ======= ======= =======
</TABLE>
<PAGE> 14
14
<TABLE>
<CAPTION>
INTER-
THREE MONTHS ENDED USA AND SEGMENT
JUNE 30, 1998 (IN THOUSANDS) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- ---------------------------- --------- ------ ----- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues:
Oil sales $ 21,134 $ 2,492 $ 23,626
Net gain on exchange rates 701 157 $ 28 886
Investment earnings and other 247 (6) 3,670 $ (215) 3,696
Intersegment revenues -- -- 2,167 (2,167) --
-------- -------- ------- ------- --------
Total revenues 22,082 2,643 5,865 (2,382) 28,208
-------- -------- ------- ------- --------
Expenses:
Lease operating costs and production
taxes 9,970 1,509 22 -- 11,501
Depletion, depreciation and
amortization 8,844 908 127 -- 9,879
General and administrative 2,433 447 3,166 -- 6,046
Interest 1,829 42 6,374 (215) 8,030
Intersegment expenses 2,167 -- -- (2,167) --
-------- -------- ------- ------- --------
Total expenses 25,243 2,906 9,689 (2,382) 35,456
-------- -------- ------- ------- --------
Loss before income taxes (3,161) (263) (3,824) -- (7,248)
Income tax expense (benefit) (7,606) 75 237 -- (7,294)
-------- -------- ------- ------- --------
Operating segment income (loss) 4,445 (338) (4,061) -- 46
Write-down and impairment of oil and
gas properties (38,400) (10,100) (5,467) -- (53,967)
Minority interest 3,878 -- -- -- 3,878
-------- -------- ------- ------- --------
Net loss $(30,077) $(10,438) $(9,528) -- $(50,043)
======== ======== ======= ======= ========
Capital expenditures $ 23,534 $ 4,499 $ 2,845 -- $ 30,878
======== ======== ======= ======= ========
</TABLE>
<TABLE>
<CAPTION>
INTER-
SIX MONTHS ENDED USA AND SEGMENT
JUNE 30, 1999 (IN THOUSANDS) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- ---------------------------- --------- ------ ----- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenue:
Oil sales $ 36,442 $ 3,948 $ 40,390
Net gain on exchange rates 626 1,627 $ 302 2,555
Investment earnings and other 277 136 5,021 $ (587) 4,847
Intersegment revenues -- -- 4,187 (4,187) --
-------- ------- -------- -------- --------
Total revenues 37,345 5,711 9,510 (4,774) 47,792
-------- ------- -------- -------- --------
Expenses:
Lease operating costs and production
taxes 19,720 2,046 17 (543) 21,240
Depletion, depreciation and
amortization 8,546 1,521 428 -- 10,495
General and administrative 3,281 844 9,940 -- 14,065
Interest 3,576 679 11,860 (587) 15,528
Intersegment expenses 3,644 -- -- (3,644) --
-------- ------- -------- -------- --------
Total expenses 38,767 5,090 22,245 (4,774) 61,328
-------- ------- -------- -------- --------
Income (loss) before income taxes (1,422) 621 (12,735) -- (13,536)
Income tax expense (benefit) 945 (106) 214 -- 1,053
-------- ------- -------- -------- --------
Operating segment income (loss) (2,367) 727 (12,949) -- (14,589)
Write-down and impairment of
oil and gas properties -- -- (1,275) -- (1,275)
Minority interest (355) -- -- -- (355)
-------- ------- -------- -------- --------
Net income (loss) $ (2,722) $ 727 $(14,224) -- $(16,219)
======== ======= ======== ======== ========
Capital expenditures $ 15,494 $ 2,083 $ 9,079 -- $ 26,656
======== ======= ======== ======== ========
Total assets $116,628 $77,531 $216,928 $(84,946) $326,141
======== ======= ======== ======== ========
</TABLE>
<PAGE> 15
15
<TABLE>
<CAPTION>
INTER-
SIX MONTHS ENDED USA AND SEGMENT
JUNE 30, 1998 (IN THOUSANDS) VENEZUELA RUSSIA OTHER ELIMINATIONS CONSOLIDATED
- ---------------------------- --------- ------ ----- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues:
Oil sales $ 48,156 $ 3,971 $ 52,127
Net gain on exchange rates 1,247 224 $ 28 1,499
Investment earnings and other 464 90 7,679 $ (393) 7,840
Intersegment revenues -- -- 4,805 (4,805) --
-------- -------- -------- -------- --------
Total revenues 49,867 4,285 12,512 (5,198) 61,466
-------- -------- -------- -------- --------
Expenses:
Lease operating costs and production
taxes 21,629 3,080 33 -- 24,742
Depletion, depreciation and
amortization 19,322 1,376 247 -- 20,945
General and administrative 4,227 900 6,325 -- 11,452
Interest 3,599 147 12,757 (393) 16,110
Intersegment expenses 4,805 -- -- (4,805) --
-------- -------- -------- -------- --------
Total expenses 53,582 5,503 19,362 (5,198) 73,249
-------- -------- -------- -------- --------
Loss before income taxes (3,715) (1,218) (6,850) -- (11,783)
Income tax expense (benefit) (8,582) 149 469 -- (7,964)
-------- -------- -------- -------- --------
Operating segment income (loss) 4,867 (1,367) (7,319) -- (3,819)
Write-down and impairment of oil and
gas properties (55,900) (10,100) (5,467) -- (71,467)
Minority interest 4,257 -- -- -- 4,257
-------- -------- -------- -------- --------
Net loss $(46,776) $(11,467) $(12,786) -- $(71,029)
======== ======== ======== ======== ========
Capital expenditures $ 53,991 $ 8,495 $ 7,725 -- $ 70,211
======== ======== ======== ======== ========
Total assets $230,155 $ 47,247 $278,452 $(58,207) $497,647
======== ======== ======== ======== ========
</TABLE>
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 $27.3 million through March 31,
1999. From April through July 1999, GEOILBENT borrowed an additional $4.9
million ($1.7 million to the Company). The proceeds from the loans are being
used by GEOILBENT to develop the North Gubkinskoye Field in West Siberia,
Russia. Because the Company accounts for its investment in GEOILBENT based on a
fiscal year ending September 30, the borrowings from April through July 1999
will be reflected in the Company's consolidated financial statements in the
quarters ending September 30 and December 31, 1999. At June 30, 1999 and
December 31, 1998, the Company's share of borrowings under these agreements (as
of March 31, 1999 and September 30, 1998 for GEOILBENT) was $9.3 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
portion of the receivable not eliminated in consolidation is included in
accounts receivable, joint interest and other. During 1996 and 1997, the Company
incurred $4.1 million in financing costs related to the establishment of the
EBRD financing, which are recorded in other assets and are subject to
amortization over the life of the facility. In 1998, under an agreement with
EBRD, GEOILBENT's board ratified an agreement to reimburse the Company for $2.6
million of such costs. However, due to GEOILBENT's need for oil and gas
investment and the declining prices for crude oil, in the second quarter of 1998
the Company agreed to defer payment of those reimbursements.
Excise, pipeline and other taxes (including a new oil export tariff introduced
in 1999) continue to be levied on all oil producers and certain exporters.
Although the Russian regulatory environment has become less volatile, the
Company is unable to predict the impact of taxes, duties and other burdens for
the future.
<PAGE> 16
16
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 June 30, 1999, the Company had loaned $13.2
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 3.6% equity interest. In December 1998 and January
1999, the Company purchased shares representing an additional 15% equity
interest not subject to any sale or transfer restrictions. The Company owned a
total of 55% of voting shares of Arctic Gas as of June 30, 1999, of which 18.6%
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 forth in the agreement (which amount is
periodically adjusted to reflect changes in the average of certain world crude
oil prices). The Venezuelan government maintains full ownership of all
hydrocarbons in the fields.
In January 1996, the Company and its bidding partners, Louisiana Land &
Exploration, which has been subsequently acquired by Burlington Resources, Inc.
("Burlington"), and Norcen Energy Resources, LTD, which has been subsequently
acquired by Union Pacific Resources Group Inc. ("UPR"), were awarded the right
to explore and develop the Delta Centro Block in Venezuela. The contract
requires a minimum exploration work program consisting of completing an 839
kilometer seismic survey and drilling three wells to depths of 12,000 to 18,000
feet within five years. At the time the block was tendered for international
bidding, PDVSA estimated that this minimum exploration work program would cost
$60 million and required that the Company and the other partners each post a
performance surety bond or standby letter of credit for its pro rata share of
the estimated work commitment expenditures. The Company has a 30% interest in
the exploration venture, with Burlington and UPR each owning a 35% interest.
Under the terms of the operating agreement, which establishes the management
company of the project, Burlington will be the operator of the field and,
therefore, the Company will not be able to exercise control of the operations of
the venture. Corporacion Venezolana del Petroleo, S.A., an affiliate of PDVSA,
has the right to obtain a 35% interest in the management company, which dilutes
the voting power of the partners on a pro rata basis. In July 1996, formal
agreements were finalized and executed, and the Company posted an $18 million
standby letter of credit, collateralized in full by a time deposit of the
Company, to secure its 30% share of the minimum exploration work program (see
Note 3). During the first quarter of 1999, drilling commenced on the Jarina-1 X,
the first of the Block's exploration wells. The well, which had a planned total
depth of 15,600 feet and was one of several structures identified from the new
3-D seismic data, penetrated a thick potential reservoir sequence, 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 June 30, 1999, the Company's share of expenditures
related to the Block was $13.1 million, and the standby letter of credit had
been reduced to $11.2 million. In July 1999, the standby letter of credit was
further reduced to $7.7 million.
<PAGE> 17
17
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 have
concluded that the well is non-commercial as a result of poor quality reservoir
rocks. Benton continues to believe that the block has high potential due to the
variety of geological play types and multiple leads and prospects. Because a
commercial well did not result from phase one, the Company and Shell will share
costs equally if the Company elects to continue to phase two. The Company and
Shell will share costs equally for the third exploration phase, if any. As of
June 30, 1999, the Company had incurred capital expenditures of $12.4 million
related to the farmout agreement.
NOTE 9 - SANTA BARBARA OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy, which held 100%
of these leases. The project area covers the Molino, Gaviota and Caliente
Fields, located approximately 35 miles west of Santa Barbara, California. In
consideration of the 40% participation interest in the leases, the Company
became the operator of the project and paid 100% of the first $3.7 million and
53% of the remainder of the costs of the first well drilled on the block. During
1998, the 2199 #7 exploratory well was drilled to the Gaviota anticline. Drill
stem tests proved to be inconclusive or non-commercial, and the well was
temporarily abandoned for further evaluation. The Company's share of the
drilling and testing of the 2199 #7 well was $8.8 million. In November 1998, the
Company entered into an agreement to acquire Molino Energy's interest in the
leases in exchange for the release of its joint interest billing obligations of
approximately $1.9 million. The agreement to acquire Molino Energy's interest
will be finalized upon the completion of certain lot splits and the assignment
of various permits and rights.
NOTE 10 - JORDAN OPERATIONS
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company is obligated to make certain capital and operating
expenditures in up to three phases over approximately eight years. The Company
is obligated to spend $5.1 million in the first exploration phase, which has
been extended to May 2000. If the Company ultimately elects to continue through
phases two and three, it would be obligated to spend an additional $18 million
over the succeeding six years. During the first quarter of 1998, the Company
reentered two wells and tested two different reservoirs. The WS-9 and WS-10
wells did not result in the production of commercial amounts of hydrocarbons.
The Company will continue to reprocess and remap seismic data and conduct
geological studies on the remaining prospectivity of the block. As of June 30,
1999, the Company had incurred capital expenditures of $3.7 million related to
the PSA.
<PAGE> 18
18
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 June 30, 1999, the Company had incurred
capital expenditures of $0.8 million related to the onshore 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 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.
NOTE 12 - RELATED PARTY TRANSACTIONS
Prior to November 30, 1998 and during 1997 and 1996, the Company made unsecured
loans documented by a promissory note bearing interest at 6% to Mr. A. E.
Benton, its Chief Executive Officer. At December 31,1997 and September 30, 1998,
the balances owed to the Company were $2.0 million and $4.4 million,
respectively. In the fourth quarter of 1998, the Company loaned Mr. Benton an
additional $1.1 million to enable him to reduce and eliminate his outstanding
margin accounts with third parties that were secured by shares of the Company's
stock. The Company then obtained a security interest in those shares of stock,
certain personal real estate and proceeds from certain contractual and stock
option agreements. At December 31, 1998, the $5.5 million owed to the Company by
Mr. Benton, which is documented by a promissory note that bears interest at 6%
and is payable on November 30, 1999, exceeded the value of the collateral,
primarily due to the decline in the price of the Company's stock. As a result,
the Company recorded an allowance for doubtful accounts of $2.9 million. 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, 1999. 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 June 30, 1999, the balance owed to the Company by Mr.
Whipkey was $0.5 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 $0.5 million and $0.6 million at June 30, 1999 and December 31, 1998,
respectively.
<PAGE> 19
19
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The Company cautions that any forward-looking statements (as such term is
defined in the Private Securities Litigation Reform Act of 1995) contained in
this report or made by management of the Company involve risks and uncertainties
and are subject to change based on various important factors. When used in this
report, the words budget, budgeted, anticipate, expect, believes, goals or
projects and similar expressions are intended to identify forward-looking
statements. In accordance with the provisions of the Private Securities
Litigation Reform Act of 1995, the Company cautions that important factors could
cause actual results to differ materially from those in the forward-looking
statements. Such factors include the Company's substantial concentration of
operations in Venezuela, the political and economic risks associated with
international operations, the anticipated future development costs for the
Company's undeveloped proved reserves, the risk that actual results may vary
considerably from reserve estimates, the dependence upon the abilities and
continued participation of certain key employees of the Company, the risks
normally incident to the operation and development of oil and gas properties and
the drilling of oil and gas wells, the price for oil and natural gas, and other
risks indicated in 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 six
months ended June 30, 1999 and 1998 and financial condition at June 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 six months ended June 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 24% lower in the first six months of 1999 compared to 1998 with a
25% decrease in oil sales quantities (from 6,836,759 Bbls of oil in 1998 to
5,100,748 Bbls of oil in 1999) offset partially by an increase in realized fees
per barrel (from $7.04 in 1998 to $7.14 in 1999). Benton-Vinccler also
experienced increased operating expenses on a per barrel basis primarily related
to workovers and plant repairs and maintenance which, especially when combined
with lower production, represented a significantly higher percentage of oil
sales revenues during the period than in the prior period.
<PAGE> 20
20
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 JUNE 30, SIX MONTHS ENDED JUNE 30,
---------------------------- ---------------------------
1999 1998 1999 1998
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Lease Operating Costs and Production Taxes 45.1% 48.7% 52.6% 47.5%
Depletion, Depreciation and Amortization 22.9 41.8 26.0 40.2
General and Administrative 37.9 25.6 34.8 22.0
Interest 34.3 34.0 38.4 30.9
</TABLE>
THREE MONTHS ENDED JUNE 30, 1999 AND 1998
The Company had revenues of $25.8 million for the three months ended June 30,
1999. Expenses incurred during the period consisted of lease operating costs and
production taxes of $10.1 million, depletion, depreciation and amortization
expense of $5.1 million, impairment of oil and gas properties of $1.3 million,
general and administrative expense of $8.5 million, interest expense of $7.7
million, income tax expense of $0.4 million and a minority interest of $0.2
million. Net loss was $7.6 million or $0.26 per share (diluted).
By comparison, the Company had revenues of $28.2 million for the three months
ended June 30, 1998. Expenses incurred during the period consisted of lease
operating costs and production taxes of $11.5 million, depletion, depreciation
and amortization expense of $9.9 million, write-down and impairment of oil and
gas properties of $54.0 million, general and administrative expense and of $6.0
million, interest expense of $8.0 million, income tax benefit of $7.3 million
and a minority interest reduction of $3.9 million. Net loss for the period was
$50.0 million or $1.69 per share (diluted).
Revenues decreased $2.4 million, or 9%, during the three months ended June 30,
1999 compared to the corresponding period of 1998 primarily due to decreased oil
sales revenue in Venezuela as a result of lower sales quantities and decreased
investment earnings which were partially offset by increased crude oil prices.
Sales quantities for the three months ended June 30, 1999 from Venezuela and
Russia were 2,441,663 Bbls and 382,165 Bbls, respectively, compared to 3,191,166
Bbls and 246,666 Bbls, respectively, for the three months ended June 30, 1998.
Prices for crude oil averaged $8.34 per Bbl (pursuant to terms of an operating
service agreement) from Venezuela and $5.41 per Bbl from Russia for the three
months ended June 30, 1999 compared to $6.62 per Bbl from Venezuela and $10.10
per Bbl from Russia for the corresponding period of 1998. Investment earnings
decreased $1.5 million, or 41%, during the three months ended June 30, 1999
compared to the three months ended June 30, 1998 due to lower average cash and
marketable securities balances. Revenues for the three months ended June 30,
1999 were increased by a foreign exchange gain of $1.1 million compared to a
gain of $0.9 million during the corresponding period of 1998.
Lease operating costs and production taxes decreased $1.4 million, or 12%,
during the three months ended June 30, 1999 compared to the three months ended
June 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 $4.8 million, or 48%, during the three
months ended June 30, 1999 compared to the corresponding period of 1998
primarily due to reduced oil sales and write-downs of oil and gas properties in
Venezuela and Russia during 1998. Depletion expense per barrel of oil equivalent
produced from Venezuela and Russia during the three months ended June 30, 1999
was $1.57 and $2.15, respectively, compared to $2.72 and $3.68, 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. 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 certain exploration
activities. General and administrative expenses increased $2.5 million, or 42%,
during the three months ended June 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 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 offset by decreased Venezuelan municipal taxes
(which are a function of oil revenues). Interest expense decreased $0.3 million,
or 4%, during the three months ended June 30, 1999 compared to the three months
ended June 30, 1998 primarily due to the capitalization of interest expense. The
Company recognized a loss before income taxes and minority interest of $6.9
million during the three months ended June 30, 1999 as compared to a loss of
$61.2 million in the corresponding period of 1998, which resulted in increased
income tax expense of $7.7 million. The loss attributable to the minority
interest decreased $46.6 million, or 86%, for the three months ended June 30,
1999 compared to the three months ended June 30, 1998 because the losses
attributable to the minority shareholders of Benton-Vinccler exceeded their
interest in equity capital and have therefore been included in the consolidated
net loss of the Company.
<PAGE> 21
21
SIX MONTHS ENDED JUNE 30, 1998 AND 1997
The Company had revenues of $47.8 million for the six months ended June 30,
1999. Expenses incurred during the period consisted of lease operating costs and
production taxes of $21.2 million, depletion, depreciation and amortization
expense of $10.5 million, impairment of oil and gas properties of $1.3 million,
general and administrative expense of $14.1 million, interest expense of $15.5
million, income tax expense of $1.1 million and a minority interest of $0.4
million. Net loss for the period was $16.2 million or $0.55 per share (diluted).
By comparison, the Company had revenues of $61.5 million for the six months
ended June 30, 1998. Expenses incurred during the period consisted of lease
operating costs and production taxes of $24.7 million, depletion, depreciation
and amortization expense of $20.9 million, write-down and impairment of oil and
gas properties of $71.5 million, general and administrative expense of $11.5
million, interest expense of $16.1 million, income tax benefit of $8.0 million,
and minority interest reduction of $4.3 million. Net loss was $71.0 million or
$2.41 per share (diluted).
Revenues decreased $13.7 million, or 22%, during the six months ended June 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
partially offset by increased crude oil prices. Sales quantities for the six
months ended June 30, 1999 from Venezuela and Russia were 5,100,748 and 715,267
Bbl, respectively, compared to 6,836,759 and 374,068 Bbl, respectively, for the
six months ended June 30, 1998. Prices for crude oil averaged $7.14 per Bbl
(pursuant to terms of an operating service agreement) from Venezuela and $5.52
per Bbl from Russia for the six months ended June 30, 1999 compared to $7.04 per
Bbl from Venezuela and $10.62 per Bbl from Russia for the corresponding period
of 1998. Investment earnings decreased $3.0 million, or 38%, during the six
months ended June 30, 1999 compared to the six months ended June 30, 1998 due to
lower average cash and marketable securities balances. Revenues for the six
months ended June 30, 1999 were increased by a foreign exchange gain of $2.6
million compared to a gain of $1.5 million during the corresponding period of
1998.
Lease operating costs and production taxes decreased $3.5 million, or 14%,
during the six months ended June 30, 1999 compared to the six months ended June
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 $10.4 million, or 50%, during the six
months ended June 30, 1999 compared to the corresponding period of 1998
primarily due to reduced oil sales in Venezuela and write-downs of oil and gas
properties in Venezuela and Russia during the six months ended June 30, 1998.
Depletion expense per barrel of oil equivalent produced from Venezuela and
Russia during the six months ended June 30, 1999 was $1.58 and $2.12,
respectively, compared to $2.78, and $3.68 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. 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 certain
exploration activities. General and administrative expenses increased $2.6
million, or 23%, during the six months ended June 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 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 offset by decreased
Venezuelan municipal taxes (which are a function of oil revenues). Interest
expense decreased $0.6 million, or 4%, during the six months ended June 30, 1999
compared to the six months ended June 30, 1998 primarily due to the
capitalization of interest. The Company recognized a loss before income taxes
and minority interest of $14.8 million during the six months ended June 30, 1999
as compared to a loss of $83.3 million in the corresponding period of 1998 which
resulted in increased income tax expense of $9.1 million. The loss attributable
to the minority interest decreased $59.4 million, or 79%, for the six months
ended June 30, 1999 compared to the six months ended June 30, 1998 because the
losses attributable to the minority shareholders of Benton-Vinccler exceeded
their interest in equity capital and have therefore been included in the
consolidated net loss of the Company.
<PAGE> 22
22
DOMESTIC OPERATIONS
In March 1997, the Company acquired a 40% participation interest in three
California State offshore oil and gas leases from Molino Energy Company, LLC
("Molino Energy"), which held 100% of these leases. The project area covers the
Molino, Gaviota and Caliente Fields, located approximately 35 miles west of
Santa Barbara, California. In consideration of the 40% participation interest in
the leases, the Company became the operator of the project and paid 100% of the
first $3.7 million and 53% of the remainder of the costs of the first well
drilled on the block. During 1998, the 2199 #7 exploratory well was drilled to
the Gaviota anticline. Drill stem tests proved to be inconclusive or
non-commercial, and the well was temporarily abandoned for further evaluation.
The Company's share of the drilling and testing of the 2199 #7 well was $8.8
million. In November 1998, the Company entered into an agreement to acquire
Molino Energy's interest in the leases in exchange for the release of its joint
interest billing obligations of approximately $1.9 million. The agreement to
acquire Molino Energy's interest will be finalized upon the completion of
certain lot splits and the assignment of various permits and rights.
INTERNATIONAL OPERATIONS
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%. However, Benton-Vinccler reported significantly lower effective tax
rates for 1996 and 1998 due to the effect of the devaluation of the Bolivar
while Benton-Vinccler uses the U.S dollar as its functional currency, and
further in 1998 due to a deferred tax asset valuation allowance. The Company
cannot predict the timing or impact of future devaluations in Venezuela.
A 3-D seismic survey has been conducted over the southwestern portion of the
Delta Centro Block in Venezuela at a total cost to the Company of $6.9 million.
During the first six months of 1999, drilling commenced on the Jarina-1 X, the
first of the block's exploration wells. The well, which had a planned total
depth of 15,600 feet and was one of several structures identified from the new
3-D seismic data, penetrated a thick potential reservoir sequence, but
encountered no hydrocarbons. The Company and its partners continue to evaluate
the remaining leads on the block, including their potential reserves and risk
factors. The Company's operations related to Delta Centro will be subject to oil
and gas industry taxation, which currently provides for royalties of 16.66% and
income taxes of 67.7%. As of June 30, 1999, the Company had incurred capital
expenditures of $13.1 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 June 30, 1999, the Company had incurred capital
expenditures of $3.7 million related to PSA.
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
<PAGE> 23
23
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 have concluded that the well is
non-commercial as a result of poor quality reservoir rocks. Benton continues to
believe that the block has high potential due to the variety of geological play
types and multiple leads and prospects. Because a commercial well did not result
from phase one, the Company and Shell will share costs equally if the Company
elects to continue to phase two. The Company and Shell will share costs equally
for the third exploration phase, if any. As of June 30, 1999, the Company had
incurred capital expenditures of $12.4 million related to the farmout agreement.
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 June 30, 1999, the Company had incurred capital
expenditures of $0.8 million related to the onshore 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 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 June 30, 1999, the Company had loaned $13.2
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 3.6% equity interest. In December 1998 and January
1999, the Company purchased shares representing an additional 15% equity
interest not subject to any sale or transfer restrictions. The Company owned a
total of 55% of the voting shares of Arctic Gas as of June 30, 1999, of which
18.6% 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.
<PAGE> 24
24
Within the United States, inflation has had a minimal effect on the Company, but
it is potentially an important factor in results of operations in Venezuela and
Russia. With respect to Benton-Vinccler and GEOILBENT, substantially all of the
sources of funds, including the proceeds from oil sales, the Company's
contributions and credit financings, are denominated in U.S. dollars, while
local transactions in Russia and Venezuela are conducted in local currency. When
the rate of increase in the value of the dollar compared to the Venezuelan
bolivar or the Russian ruble is less than the rate of inflation in these
countries, then inflation could be expected to have an adverse effect on the
Company.
During the six months ended June 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
six months ended June 30, 1999, were $0.9 million and $1.6 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 six months ended June 30 are summarized in the
following table and discussed in further detail below (in thousands):
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
-------------------------------
1999 1998
------- -------
<S> <C> <C>
Net cash provided by (used in) operating activities $(1,595) $13,027
Net cash provided by (used in) investing activities 335 (6,754)
Net cash provided by financing activities 1,719 4,437
------- -------
Net increase in cash $ 459 $10,710
======= =======
</TABLE>
At June 30, 1999, the Company had current assets of $57.2 million and current
liabilities of $36.1 million resulting in working capital of $21.1 million and a
current ratio of 1.6:1. 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 $34.8
million was due primarily to expenditures related to exploration and development
in Venezuela, Russia and China and lower oil sales as a result of declines in
world crude oil prices and oil sales quantities.
CASH FLOW FROM OPERATING ACTIVITIES. During the six months ended June 30, 1999,
net cash used in operating activities was approximately $1.6 million, and for
the six months ended June 30, 1998, net cash provided by operating activities
was approximately $13.0 million. Cash flow from operating activities decreased
by $14.6 million during the six months ended June 30, 1999 compared to the
corresponding period of the prior year due primarily to reduced collections of
accrued oil revenues as a result of lower crude oil prices.
CASH FLOW FROM INVESTING ACTIVITIES. During the six months ended June 30, 1999
and 1998, the Company had drilling and production related capital expenditures
of approximately $26.7 million and $70.2 million, respectively. Of the 1999
expenditures, $10.4 million was attributable to the development of the South
Monagas Unit in Venezuela, $1.4 million related to the development of the North
Gubkinskoye Field in Russia, $5.1 million related to a 3-D seismic survey and
exploratory well costs in the Delta Centro Block in Venezuela, $8.2 million
related to the development of the Qingshui Block in China, $0.7 million related
to the Samburg Block in Russia (in addition to $13.2 million loaned to Arctic
Gas) and $0.9 million was attributable to other projects. The capital
expenditures during the six months ended June 30, 1999 and 1998 were
substantially offset by net redemptions of marketable securities of $35.3
million and $65.9 million, respectively.
<PAGE> 25
25
During 1998, the Company instituted a capital expenditure program which
minimized expenditures to those that the Company believed were necessary in
order to maintain current producing properties. This policy was instituted in
response to the low market price for oil. The Company expects to continue
limiting capital expenditures at this maintenance level until such time as cash
flow from operating, investing and/or financing activities permit resumption of
exploration and development programs on a broader scale.
The Company expects 1999 capital expenditures of $40-50 million, including $7-8
million in expenditures by GEOILBENT in Russia, net to the Company's interest
(which are expected to be funded from borrowings under the EBRD Credit Facility,
cash flow from operations or other financings). Additionally, the Company
anticipates providing or arranging loans of up to $100 million over the next two
years to Arctic Gas pursuant to an equity acquisition agreement signed in April
1998. The Company is currently evaluating funding alternatives for the loans to
Arctic Gas. The Company's indentures contain provisions that restrict the manner
in which the Company can invest in certain of its current operations including
GEOILBENT.
The Company continually assesses its 1999 capital expenditure program in view of
its financial resources and of industry and commodity price changes. Its total
1999 capital expenditure requirements include approximately $10-15 million at
South Monagas Unit, $16-18 million for well commitments in China and at Delta
Centro, and $9-10 million for Arctic Gas. The Company anticipates that Geoilbent
will continue to fund itself through its own cash flows and credit facilities.
The Company's remaining capital commitments worldwide are relatively minimal and
for the most part are substantially at the Company's discretion. The timing and
size of the 1999 investments for Arctic Gas are also substantially under the
Company's discretion. The Company believes it has or can obtain sufficient
funding for certain of its expected capital requirements from working capital
and cash flow from operations.
The Company's future financial condition and results of operations will largely
depend upon prices received for its oil production and the costs of acquiring,
finding, developing and producing reserves. Prices for oil are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond the Company's control.
If oil prices continue at or near current levels, and if oil production
continues at expected levels, the Company believes that its current cash and
cash provided by operating activities will be sufficient to meet the Company's
liquidity needs for routine operations and to service its outstanding debt
(including $15.5 million in interest payments) through 1999. If oil prices and
production volumes later in 1999 and early in 2000 result in cash flows that are
less than currently planned, then the Company may have to reduce further its
planned capital and operating expenditures in 2000, which could have negative
effects on future oil production rates. The Company continues to evaluate and
review strategic alternatives and has engaged J.P. Morgan Securities, Inc. to
advise the Company related to these alternatives. In the event that future cash
requirements are greater than the Company's financial resources, the Company
intends to pursue strategic joint ventures or alliances with other industry
partners, sell property interests, merge or combine with another entity, or
issue debt or equity securities. There can be no assurance that any such
transaction would be available on terms acceptable to the Company.
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 June 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 $32.2 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, and the Russian subsidiaries are in the process of installing and
testing their accounting software programs with completion anticipated in the
third quarter of 1999. All other "mission critical" office business systems are
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
<PAGE> 26
26
systems such as plant flow control devices, product measurement and delivery
devices and fire or other disaster-related safety systems has been underway
since mid-1998. 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 preparing 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 lasting until 2012, represented approximately 91% of
the Company's oil sales during 1998 and 90% for the six months ended June 30,
1999. In the event that PDVSA is unable to accept deliveries of, or make payment
for, the oil produced by the Company due to a Year 2000 failure, the Company's
operations and financial position could be materially and adversely affected.
The failure to correct a material Year 2000 problem could result in an
interruption in, or a failure of, certain normal business activities or
operations. Such failures could materially and adversely affect the Company's
results of operations, liquidity and financial condition. Due to the general
uncertainty inherent in the Year 2000 problem, resulting in part from the
uncertainty of the Year 2000 readiness of third-party suppliers and customers,
the Company is unable to determine at this time whether the consequences of Year
2000 failures will have a material impact on the Company's results of
operations, liquidity or financial condition.
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
declined from $10.07 in 1997 to $6.94 in 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, and does not expect to utilize such transactions in the
near future. 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.
The Company did not enter into any commodity hedging agreements during 1997,
1998 and 1999.
INTEREST RATES
Total long term debt of $290.4 million at June 30, 1999, included $230 million
of fixed-rate senior unsecured notes maturing in 2003 ($125 million) and 2007
($105 million). Another $51.0 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 $9.4 million (3%
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 six months ended
June 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
<PAGE> 27
27
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> 28
28
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
At the Annual Meeting of the Stockholders of the Company held on June
30, 1999, the following items were voted upon by the Stockholders:
1. Election of Directors:
<TABLE>
<CAPTION>
VOTES AGAINST/ ABSTENTIONS/
VOTES IN FAVOR WITHHELD BROKER NON-VOTES
-------------- -------- ----------------
<S> <C> <C> <C>
Alex E. Benton 24,573,972 1,684,739 0
Michael B. Wray 24,710,677 1,548,034 0
Bruce M. McIntyre 24,626,916 1,631,795 0
Richard W. Fetzner 24,701,313 1,557,398 0
Garrett A. Garrettson 24,618,168 1,640,543 0
</TABLE>
2. To approve and ratify the appointment of
PricewaterhouseCoopers LLP as independent accountants for the
fiscal year ending December 31, 1999:
<TABLE>
<CAPTION>
VOTES AGAINST/ ABSTENTIONS/
VOTES IN FAVOR WITHHELD BROKER NON-VOTES
-------------- -------- ----------------
<S> <C> <C> <C>
25,104,543 107,725 1,046,443
</TABLE>
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None.
(b) Reports on Form 8-K
None.
<PAGE> 29
29
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: August 13, 1999 By: /s/ A.E.BENTON
--------------------------------------
A.E. Benton
President and Chief Executive Officer
Dated: August 13, 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 JUNE 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> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<EXCHANGE-RATE> 1
<CASH> 18,606
<SECURITIES> 5,827
<RECEIVABLES> 20,743
<ALLOWANCES> 6,021
<INVENTORY> 0
<CURRENT-ASSETS> 57,243
<PP&E> 519,317
<DEPRECIATION> 350,947
<TOTAL-ASSETS> 326,141
<CURRENT-LIABILITIES> 36,073
<BONDS> 290,373
0
0
<COMMON> 296
<OTHER-SE> (1,431)
<TOTAL-LIABILITY-AND-EQUITY> 326,141
<SALES> 40,390
<TOTAL-REVENUES> 47,792
<CGS> 31,735
<TOTAL-COSTS> 31,735
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 15,528
<INCOME-PRETAX> (14,811)
<INCOME-TAX> 1,053
<INCOME-CONTINUING> (16,219)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (16,219)
<EPS-BASIC> (.55)
<EPS-DILUTED> (.55)
</TABLE>
