1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
Quarterly Report UnderPursuant to Section 13 or 15(d)
[X] of the Securities Exchange Act of 1934
For the Quarterly Period Ended September 30, 20002001 or
Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from _____ to _____
COMMISSION FILE NO. 1-10762
---------------
BENTON OIL AND GAS COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 77-0196707
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
Identification Number)
6267 CARPINTERIA AVE.,15835 PARK TEN PLACE DRIVE, SUITE 200
CARPINTERIA, CALIFORNIA 93013115
HOUSTON, TEXAS 77084
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (805) 566-5600
---------------(281) 579-6700
Indicate by check mark whether the Registrant (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
--- ---
-------------------- -----
At November 14, 2000, 33,821,91912, 2001, 33,946,919 shares of the
Registrant's Common Stock were outstanding.
2
2
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
PAGEPage
----
PART I FINANCIAL INFORMATION
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets at September 30, 20002001
and December 31, 19992000 (Unaudited).........................................3........................................................3
Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 2001 and 2000 and 1999 (Unaudited)......................4.....................................4
Consolidated Statements of Cash Flows for the Nine
Months Ended September 30, 2001 and 2000 and 1999 (Unaudited)......................5.....................................5
Notes to Consolidated Financial Statements.......................................7Statements......................................................6
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS...............................................21OPERATIONS..............................................................22
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........................29RISK.......................................34
PART II.II OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS.................................................................30PROCEEDINGS................................................................................36
Item 2. CHANGES IN SECURITIES.............................................................30SECURITIES AND USE OF PROCEEDS........................................................36
Item 3. DEFAULTS UPON SENIOR SECURITIES...................................................30SECURITIES..................................................................36
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...............................30HOLDERS..............................................36
Item 5. OTHER INFORMATION.................................................................30INFORMATION................................................................................36
Item 6. EXHIBITS AND REPORTS ON FORM 8-K..................................................30
SIGNATURES................................................................................................318-K.................................................................36
SIGNATURES...............................................................................................................37
3
3
PART I. FINANCIAL INFORMATION
ItemITEM 1. FINANCIAL STATEMENTS
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, unaudited)
SEPTEMBER 30, DECEMBER 31,
2001 2000
1999
------------- ------------------------------- -----------------
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents $ 21,11618,461 $ 21,14715,132
Restricted cash 34,58712 12
Marketable securities 2,067 4,469- 1,303
Accounts and notes receivable:
Accrued oil and gas revenue 37,092 27,33930,590 38,003
Joint interest and other, net 6,345 4,9939,740
6,778
Prepaid expenses and other 625 1,635
--------- ---------1,562 2,404
------------ ------------
TOTAL CURRENT ASSETS 101,832 59,59560,365 63,632
RESTRICTED CASH 10,848 46,44916 10,920
OTHER ASSETS 6,278 10,5695,059 5,891
DEFERRED INCOME TAXES 12,150 12,1864,827 4,293
INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES 72,565 61,35799,373 77,741
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of $16,357$17,935 and
$16,117$16,634 excluded from amortization in 2001 and 2000, and 1999, respectively) 474,723 435,449524,659 490,548
Furniture and fixtures 10,760 10,031
--------- ---------
485,483 445,48010,519 11,049
------------ ------------
535,178 501,597
Accumulated depletion, impairment and depreciation (371,945) (359,325)
--------- ---------
113,538 86,155
--------- ---------(395,677) (377,627)
------------ ------------
139,501 123,970
------------ ------------
$ 317,211309,141 $ 276,311
========= =========286,447
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
(DEFICIT)
- ----------------------------------------------------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other $ 11,3594,198 $ 3,31712,804
Accrued expenses 30,428 25,797
Accrued interest payable 9,698 4,686
Accrued expenses 24,816 17,1059,480 3,733
Income taxes payable 12,406 2,39210,200 3,214
Short-term borrowings - 5,714
Current portion of long-term debt 34,575 2
--------- ---------2,457 -
------------ ------------
TOTAL CURRENT LIABILITIES 92,854 27,50256,763 51,262
LONG-TERM DEBT 217,000 264,575221,598 213,000
OTHER LIABILITIES 1,138 -
COMMITMENTS AND CONTINGENCIES
MINORITY INTERESTS 6,390 1,412INTEREST 13,638 9,281
STOCKHOLDERS' EQUITY (DEFICIT):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 32,37233,947 shares at September 30, 20002001 and 29,62733,872 shares at
December 31, 1999 324 2962000 339 339
Additional paid-in capital 153,494 147,078
Retained156,874 156,629
Accumulated deficit (152,152) (163,853)(140,510) (143,365)
Treasury stock, at cost, 50 shares (699) (699)
--------- ---------------------
------------
TOTAL STOCKHOLDERS' EQUITY (DEFICIT) 967 (17,178)
--------- ---------16,004 12,904
------------ ------------
$ 317,211309,141 $ 276,311
========= =========286,447
============ ============
See accompanying notes to consolidated financial statements.
4
4
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data, unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ -------------------------------
2001 2000 19992001 2000 1999
------------- ------------ ------------- ------------
REVENUES
Oil and natural gas sales $ 31,370 $ 37,972 $ 24,565 $101,51698,552 $ 61,006
-------- -------- -------- --------101,516
----------- ---------- ----------- -----------
31,370 37,972 24,56598,552 101,516
61,006
-------- -------- -------- ------------------- ---------- ----------- -----------
EXPENSES
Operating expenses 9,683 12,983 10,18032,188 34,767 29,620
Depletion, depreciation and amortization 5,963 4,141 3,77718,668 11,654 12,752
Write-downs of oil and gas properties and impairments - 13,047- 411 1,069 14,322
General and administrative 5,456 3,782 4,44415,876 12,324 16,852
Taxes other than on income 1,243 1,364 1,0944,369 3,460
2,452
-------- -------- -------- ------------------- ---------- ----------- -----------
22,345 22,270 32,54271,512 63,274
75,998
-------- -------- -------- ------------------- ---------- ----------- -----------
INCOME (LOSS) FROM OPERATIONS 9,025 15,702 (7,977)27,040 38,242 (14,992)
OTHER NON-OPERATING INCOME (EXPENSE)
Investment income and other 710 2,234 2,2942,373 6,562 7,006
Interest expense (6,126) (7,318) (7,187)(18,464) (22,228) (22,036)
Net gain (loss) on exchange rates 297 67 (16)516 200
913
-------- -------- -------- ------------------- ---------- ----------- -----------
(5,119) (5,017) (4,909)(15,575) (15,466)
(14,117)
-------- -------- -------- ------------------- ---------- ----------- -----------
INCOME (LOSS) FROM CONSOLIDATED COMPANIES
BEFORE INCOME TAXES AND MINORITY INTERESTS 3,906 10,685 (12,886)11,465 22,776 (29,109)
INCOME TAX EXPENSE 3,510 5,018 92310,587 13,309
2,082
-------- -------- -------- ------------------- ---------- ----------- -----------
INCOME (LOSS) BEFORE MINORITY INTERESTS 396 5,667 (13,809)878 9,467 (31,191)
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
COMPANIES 1,523 2,007 1774,357 4,978
532
-------- -------- -------- ------------------- ---------- ----------- -----------
INCOME (LOSS) FROM CONSOLIDATED COMPANIES (1,127) 3,660 (13,986)(3,479) 4,489 (31,723)
EQUITY IN NET EARNINGS (LOSSES) OF AFFILIATED COMPANIES 2,859 2,213 (143)6,334 4,117
1,375
-------- -------- -------- ------------------- ---------- ----------- -----------
INCOME (LOSS) BEFORE EXTRAORDINARY INCOME 1,732 5,873 (14,129)2,855 8,606 (30,348)
EXTRAORDINARY INCOME ON DEBT REPURCHASE,
NET OF TAX OF $0 - 3,095 - 3,095
-
-------- -------- -------- ------------------- ---------- ----------- -----------
NET INCOME (LOSS)$ 1,732 $ 8,968 $(14,129)$ 2,855 $ 11,701
$(30,348)
======== ======== ======== =================== ========== =========== ===========
NET INCOME (LOSS) PER COMMON SHARE:
Basic:
Income (loss) before extraordinary income $ 0.05 $ 0.19 $ (0.48)0.08 $ 0.29
Extraordinary income - 0.10 - 0.10
----------- ---------- ----------- -----------
Net income $ 0.05 $ 0.29 $ (1.03)
Extraordinary income 0.10 - 0.10 -
-------- -------- -------- ---------
Net income (loss) $ 0.29 $ (0.48)0.08 $ 0.39
$ (1.03)
======== ======== ======== ==================== ========== =========== ===========
Diluted:
Income (loss) before extraordinary income $ 0.05 $ 0.19 $ (0.48)0.08 $ 0.29
Extraordinary income - 0.10 - 0.10
----------- ---------- ----------- -----------
Net income $ 0.05 $ 0.29 $ (1.03)
Extraordinary income 0.10 - 0.10 -
-------- -------- -------- ---------
Net income (loss) $ 0.29 $ (0.48)0.08 $ 0.39
$ (1.03)
======== ======== ======== ==================== ========== =========== ===========
See accompanying notes to consolidated financial statements.
5
5
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands, unaudited)
NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------------------------------------------
2001 2000
1999
----------- ----------------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIESACTIVITIES:
Net Income (loss)income $ 2,855 $ 11,701 $(30,348)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities: 18,668 11,654
Depletion, depreciation and amortization 11,654 12,752411 1,069
Write-downs of oil and gas properties and impairments 1,069 14,322944 1,047
Amortization of financing costs 1,047 1,047
Loss on disposal of assets -- 20 39
Equity in earnings of affiliated companies (6,334) (4,117) (1,375)
Allowance for employee notes and accounts receivable 247 2,868247
Non-cash compensation-related charges 245 --
4,357 4,978
Minority interest in undistributed earnings of subsidiary 4,978 532subsidiaries
Extraordinary income from repurchase of debt -- (3,095)
--(534) 36
Deferred income taxes 36 (255)
Changes in operating assets and liabilities:
Accounts and notes receivable 4,204 (8,754) (3,418)
Prepaid expenses and other 842 1,010 539
Accounts payable (8,606) 8,042
(3,017)Accrued expenses 4,631 7,711
Accrued interest payable 5,747 5,012 4,994
Accrued expenses 7,711 1,754
Income taxes payable 6,986 10,014 976
-------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 34,663 46,575 1,410
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property and equipment -- 15,000ACTIVITIES:
Additions of property and equipment (34,610) (40,127)
(29,430)
InvestmentsInvestment in and advances to affiliated companies (15,298) (7,091) (10,523)
Increase in restricted cash (57) (199) (213)
Decrease in restricted cash 10,961 1,225 18,572
Purchase of marketable securities (15,067) (13,650) (26,766)
Maturities of marketable securities 16,370 16,052
51,605-------- --------
NET CASH USED IN INVESTING ACTIVITIES (37,701) (43,790)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from exercise of stock options -- 260
Proceeds from issuance of short-term borrowings and notes payable 21,111 --
Payments on short-term borrowings and notes payable (14,632) (3,539)
(Increase) decrease in other assets (112) 463
-------- --------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (43,790) 18,245
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES Net proceeds from exercise of stock options and warrants 260 2
Payments on short-term borrowings and notes payable (3,539) (15,072)
(Increase) decrease in other assets 463 (249)
-------- --------
NET CASH USED IN FINANCING ACTIVITIES6,367 (2,816) (15,319)
-------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3,329 (31) 4,336
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 15,132 21,147 17,198
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 21,11618,461 $ 21,53421,116
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
$ 13,512 $ 14,749
Cash paid during the period for interest expense $ 14,749 $ 18,267 ======== ========
Cash paid during the period for income taxes $ 1,5591,711 $ 8991,559
======== ========
See accompanying notes to consolidated financial statements.
6
6
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
During the nine months ended September 30, 2000, the Companywe repurchased $8,000,000$8 million face
value of itsour senior unsecured notes with the issuance of 2,710,590 shares of
common stock.
During the nine months ended September 30, 1999 the Company recorded an
allowance for doubtful accounts related to amounts owed to the Company by its
former Chief Executive Officer (See note 12).
See accompanying notes to consolidated financial statements.
7
76
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
NINE MONTHS ENDED SEPTEMBER 30, 20002001 (UNAUDITED)
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Benton Oil and Gas Company (the "Company") engagesWe engage in the exploration, development, production and management of oil and
gas properties. The Company
conducts itsWe conduct our business principally in Venezuela and Russia.
The consolidated financial statements include the accounts of all wholly-owned
and majority-owned subsidiaries. The equity method of accounting is used for
companies and other investments inover which the Company haswe have significant influence. All
intercompany profits, transactions and balances have been eliminated. The
Company accountsWe account
for itsour investment in Geoilbent, Ltd. ("Geoilbent") and Arctic Gas Company
("Arctic Gas"), formerly Severneftegaz, based on a fiscal year ending September 30 (see Note 2).
In January 2000, in connection with the release of Emerging Issues Task Force
(EITF) Issues Summary 00-01, "Applicability of the Pro Rata Method of
Consolidation to Investments in Certain Partnerships and Other Unincorporated
Joint Ventures", the Company reviewed the accounting for its investment in
Geoilbent under the proportionate consolidation method. As a result of this
review, the Company decided to report its investment in Geoilbent using the
equity method. This change had no effect on net income or the Company's
proportionate share of oil and gas reserves. It did, however, result in the
reduction of the Company's reported consolidated net cash flows for the nine
months ended September 30, 1999 of $1.0 million. For the three and nine month
periods ended September 30, 1999, revenues were reduced by the Company's
proportionate share, which was $2.4 million and $6.3 million, respectively,
expenses were reduced $1.8 million and $5.4 million, respectively, and net other
non-operating expenses were decreased by $0.2 million and increased by $0.9
million, respectively. Summarized financial information for Geoilbent is
included in Note 7.
INTERIM REPORTING
In theour opinion, of the Company, the accompanying unaudited consolidated financial statements
contain all adjustments (consisting of only normal recurring accruals) necessary
to present fairly the financial position as of September 30, 2000,2001, and the
results of operations for the three and nine month periods ended September 30,
20002001 and 19992000 and cash flows for the nine month periods ended September 30, 20002001
and 1999.2000. The unaudited financial statements are presented in accordance with
the requirements of Form 10-Q and do not include all disclosures normally
required by accounting principles generally accepted in the United States of
America. Reference should be made to the Company'sour consolidated financial statements and
notes thereto included in the Company'sour Annual Report on Form 10-K for the year ended
December 31, 19992000, for additional disclosures, including a summary of the Company'sour
accounting policies.
The results of operations for the three and nine month periods ended September
30, 20002001 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 accounting principles
generally accepted in the United States of America requires managementus to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
ACCOUNTS AND NOTES RECEIVABLE
Allowance for doubtful accounts related to employee notes was $6.1$6.4 million and
$5.9$6.2 million at September 30, 20002001 and December 31, 1999,2000, respectively (see Note
12)11). Allowance for doubtful accounts related to joint interest and other
accounts receivable was $0.3 million at September 30, 2000 and December 31, 1999.2000.
MINORITY INTERESTS
The Company recordsWe record a minority interest attributable to the minority shareholders of itsour
subsidiaries. The minority interests in net income and losses are generally
subtracted or added to arrive at consolidated net income.
However, as of September 30, 1999, losses attributable to the minority
shareholder of Benton-Vinccler, a subsidiary owned 80% by the Company, exceeded
its interest in equity capital. Accordingly, $0.2 million of Benton-Vinccler's
net income for the nine month period ended September 30, 1999 attributable to
the minority shareholder has been included in the consolidated net loss of the
Company. No such adjustment was necessary for the nine months ended September
30, 2000.
8
8
MARKETABLE SECURITIES
Marketable securities are carried at amortized cost. The marketable securities
the Companywe may purchase are limited to those defined as Cash Equivalents in the
indentures for itsour 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'sOur marketable securities at cost, which approximates fair
value, consisted of $2.1$1.3 million and $4.5 million inof commercial paper at September 30, 2000 and December 31, 1999, respectively.2000.
7
COMPREHENSIVE INCOME
Statement of Financial Accounting Standards No. 130 ("SFAS 130") requires that
all items that are required to be recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements. The CompanyWe did not
have any items of other comprehensive income during the three and nine month
periods ended September 30, 20002001 or September 30, 19992000 and, in accordance with
SFAS 130, hashave not provided a separate statement of comprehensive income.
NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) No. 141, "Business Combinations," SFAS
142 "Goodwill and Other Intangible Assets" and SFAS 143 "Accounting for Asset
Retirement Obligations." SFAS 141 eliminates the pooling method of accounting
for a business combination, except for qualifying business combinations that
were initiated prior to July 1, 2001, and requires that all combinations be
accounted for using the purchase method. SFAS 142, which is effective for fiscal
years beginning after December 15, 2001, addresses accounting for identifiable
intangible assets, eliminates the amortization of goodwill and provides specific
steps for testing the impairment of goodwill. Separable intangible assets that
are not deemed to have an indefinite life will continue to be amortized over
their useful lives. SFAS 143, which is effective for fiscal years beginning
after June 15, 2002, requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred as a
capitalized cost of the long-lived asset and to depreciate it over its useful
life. We are currently in the process of evaluating the impact that SFAS 142 and
SFAS 143 will have on our financial position and results of operations.
In October 2001, the FASB issued SFAS 144, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which addresses
financial accounting and reporting for the impairment or disposal of long-lived
assets. SFAS 144 supersedes SFAS 121 and the accounting and reporting provisions
of APB Opinion No. 30. SFAS 144 is effective for fiscal years beginning after
December 15, 2001. We are currently in the process of evaluating the impact that
SFAS 144 will have on our financial position and results of operations.
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 structuresstructures. The numerator
(income), denominator (shares) and amount of the basic and diluted earnings per
share computations for income were (in thousands, except per share amounts):
9
9
INCOME/ AMOUNT PER
(LOSS)INCOME SHARES SHARE
----------- ------ ----------------------- ------------ ------------
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000
-2001
---------------------------------------------
BASIC EPS
Income before extraordinary itemattributable to common stockholders $ 1,732 33,947 $ 0.05
======== ========= ========
Effect of dilutive securities:
Stock options and warrants - 3
-------- ---------
DILUTED EPS
Income attributable to common stockholders $ 1,732 33,950 $ 0.05
======== ========= ========
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000
BASIC EPS
Income attributable to common stockholders $ 5,873 30,339 $ 0.19
=========== ====== =============== ========= ========
Effect of dilutive securities:
Stock options and warrants --- 192
----------- ------------- ---------
DILUTED EPS
Income before extraordinary item attributable to common stockholders $ 5,873 30,531 $ 0.19
=========== ====== =============== ========= ========
8
AMOUNT PER
INCOME SHARES SHARE
------------- ------------ ------------
FOR THE THREENINE MONTHS ENDED SEPTEMBER 30, 1999
- ---------------------------------------------2001
--------------------------------------------
BASIC EPS
LossIncome attributable to common stockholders $ (14,129) 29,5772,855 33,945 $ (0.48)
=========== ====== =======0.08
======== ======== ========
Effect of dilutive securities:
Stock options and warrants - 68
-------- --------
DILUTED EPS
LossIncome attributable to common stockholders 2,855 34,013 $ (14,129) 29,577 $ (0.48)
=========== ====== =======
INCOME/ AMOUNT PER
(LOSS) SHARES SHARE
---------- ------ ----------0.08
======== ======== ========
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
- --------------------------------------------
BASIC EPS
Income before extraordinary item attributable to common stockholders $ 8,606 29,865 $ 0.29
=========== ====== =======$0.29
======== ======== ========
Effect of Dilutive Securities:dilutive securities:
Stock options and warrants --- 243
----------- -------------- --------
DILUTED EPS
Income before extraordinary item attributable to common stockholders $ 8,606 30,108 $ 0.29
=========== ====== =======
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
- --------------------------------------------
BASIC EPS
Loss attributable to common stockholders $ (30,348) 29,577 $ (1.03)
=========== ====== =======
DILUTED EPS
Loss attributable to common stockholders $ (30,348) 29,577 $ (1.03)
=========== ====== =======$0.29
======== ======== ========
An aggregate of 7.8 million and 5.6 million and 5.7 millionshares that may be issued on the
exercise of options and warrants were excluded from the earnings per share
calculations because the exercise price exceeded the average share price during
the three and nine month periods ended September 30, 2001 and 2000, respectively. An
aggregate 6.0of 6.7 million and 5.05.7 million shares that may be issued on the
exercise of options and warrants were excluded from the earnings per share
calculation forcalculations because the three andexercise price exceeded the average share price during
the nine month periods ended September 30, 1999, respectively, because they were
anti-dilutive.2001 and 2000, respectively.
PROPERTY AND EQUIPMENT
The Company followsWe follow the full cost method of accounting for oil and gas properties with
costs accumulated in cost centers on a country by country basis, subject to a
cost center ceiling (as defined by the Securities and Exchange Commission). All
costs associated with the acquisition, exploration, and development of oil and
natural gas reserves are capitalized as incurred, including exploration overhead
of $0.4$0.6 million and $1.7$0.4 million for the nine months ended September 30, 20002001
and 1999,2000, respectively, and capitalized interest of $0.4$0.7 million and $1.7$0.4
million for the nine months ended September 30, 20002001 and 1999,2000, respectively.
Only overhead that is directly identified with acquisition, exploration or
development activities is capitalized. All costs related to production, general
corporate overhead and similar activities are expensed as incurred.
The costs of unproved properties are excluded from amortization until the
properties are evaluated. Excluded costs attributable to the China and other
cost centers were $16.4$17.9 million and $16.1$16.6 million at September 30, 20002001 and
December 31, 1999,2000, respectively. The CompanyWe regularly evaluates itsevaluate our unproved properties
on a country by country basis for possible impairment. If the Company
abandonswe abandon all
exploration efforts in a country where no proved reserves are assigned, all
exploration and acquisition costs associated with the country are expensed. Due
to the unpredictable nature of exploration drilling activities, the amount and
timing of impairment expenses are difficult to predict with any certainty.
The principal portionSubstantially all of the excluded costs except those relatedat September 30, 2001 and December 31,
2000 relate to the acquisition of Benton Offshore China Company isand evaluation
related to its Wan `An Bei property. The remaining excluded costs of $0.9
million are expected to be included in amortizable costs during the next two to
three years. It is uncertainThe ultimate timing of when the costs related to the acquisition of
Benton Offshore China Company will be included in amortizable costs.
10
10costs is
uncertain.
All capitalized costs and estimated future development costs (including
estimated dismantlement, restoration and abandonment costs) of proved reserves
are depleted using the units of production method based on the total proved
reserves of the country cost center. Depletion expense, which was substantially
all attributable
primarily to the Venezuelan cost center, for the nine months ended
September 30, 2001 and 2000, was $15.6 million and 1999 was $10.2 million ($2.12 and
$11.5 million ($1.48 and $1.55$1.48 per equivalent barrel), respectively. Depreciation of furniture and
fixtures is computed using the straight-line method with depreciation rates
based upon the estimated useful life of the property, generally 5five years.
Leasehold improvements are depreciated over the life of the applicable lease.
Depreciation expense was $1.3$3.0 million and $1.2$1.3 million for the nine-monthsnine months ended
September 30, 2001 and 2000, respectively. Additionally, as a result of the
reduction in force and 1999, respectively.
COST REDUCTIONScorporate restructuring discussed below, the value of
unamortized leasehold improvements has been reduced by $1.4 million for the
anticipated loss on subleasing our former corporate headquarters and the
carrying value of fixed assets has been reduced by $0.4 million.
9
REDUCTION IN FORCE AND CORPORATE RESTRUCTURING
In an effortJune 2001, we implemented a plan designed to reduce general and
administrative costs, including exploration overhead, at our corporate
headquarters and to transfer geological and geophysical activities to our
overseas offices in Maturin, Venezuela and in Western Siberia and Moscow,
Russia. The reduction in general and administrative costs is being accomplished
by reducing our headquarters staff and relocating our headquarters to Houston,
Texas from Carpinteria, California. In June 2001, we recorded restructuring
charges of $2.1 million, $0.9 million of which are included in general and
administrative expenses and $1.2 million of which are included in depletion,
depreciation and amortization. The restructuring charges included $0.9 million
for severance and termination benefits for 27 employees, $0.8 million for the
Company reduced
itsanticipated loss on subleasing the former Carpinteria, California headquarters
and $0.4 million for the reduction in the carrying value of fixed assets that
were not transferred to Houston. In September 2001, we recorded additional
restructuring charges of $1.4 million related to the Carpinteria, California
building lease due to changes in the local commercial building lease market,
$0.8 million of which are included in general and administrative expenses and
technical staff$0.5 million of which are included in Carpinteriadepletion, depreciation and amortization.
The implementation of the plan was substantially complete by 10 personsthe end of the
third quarter of 2001. From June through September 2001, 21 employees were
terminated and $0.7 million in October
1999. In connectionseverance payments were paid. As of September 30,
2001, the accrued expenses associated with the reduction in staff,force and corporate
restructuring plan, including anticipated costs to terminate the Company recorded
termination benefits expenses in October 1999building lease
of the former Carpinteria, California headquarters office of $0.8 million, were
$1.0 million. All amounts wereThe accrued expenses are expected to be paid asby the end of September 30, 2000.the
first quarter of 2002.
RECLASSIFICATIONS
Certain items in 19992000 have been reclassified to conform to the 20002001 financial
statement presentation.
NOTE 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES
Investments in Geoilbent and Arctic Gas are accounted for using the equity
method due to the significant influence the Company exerciseswe exercise over their operations and
management. Investments include amounts paid to the investee companies for
shares of stock or joint venture interests and other costs incurred associated
with the acquisition and evaluation of technical data for the oil and natural
gas fields operated by the investee companies. Other investment costs are
amortized using the units of production method based on total proved reserves of
the investee companies. Equity in earnings of Geoilbent and Arctic Gas are based
on a fiscal year ending September 30. No dividends have been paid to the Company
from Geoilbent or Arctic Gas.
Equity in earnings and losses and investments in and advances to companies
accounted for using the equity method are as follows (in thousands):
GEOILBENT, LTD. ARCTIC GAS COMPANY TOTAL
-------------------------- --------------------------- --------------------------------------------------- ------------------------- ------------------------
SEP 30, DEC 31, SEP 30, DEC 31, SEP 30, DEC 31,
2001 2000 19992001 2000 19992001 2000
1999---------- ---------- ----------- ----------- ----------- ----------- ----------- --------------------- ---------- ----------
Investments
Equity in net assets $28,056 $28,056 $(2,879) $ (2,419) $25,177 $25,63728,056 $ 28,056 $(2,558) $(2,218) $ 25,498 $ 25,838
Other costs, net of amortization (135) (542) 19,024 17,128 18,889 16,586(103) (202) 28,127 19,058 28,024 18,856
---------- ---------- --------------------- ---------- ---------- ----------
Total investments 27,921 27,514 16,145 14,709 44,066 42,22327,953 27,854 25,569 16,840 53,522 44,694
Advances - - 18,630 13,364 18,630 13,36428,466 21,986 28,466 21,986
Equity in earnings (losses) 10,953 6,167 (1,084) (397) 9,869 5,77019,134 12,310 (1,749) (1,249) 17,385 11,061
---------- ---------- --------------------- ---------- ---------- ----------
Total $38,874 $33,681 $33,691 $ 27,676 $72,565 $61,35747,087 $ 40,164 $ 52,286 $ 37,577 $ 99,373 $ 77,741
========== ========== ===================== ========== ========== ==========
11
1110
NOTE 3 - LONG-TERM DEBT AND LIQUIDITY
LONG-TERM DEBT
Long-term debt consists of the following (in thousands):
SEPTEMBER 30, DECEMBER 31,
2001 2000
1999
-------------- ----------------------------- ----------------
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. 112,000 125,000
Benton-Vinccler credit facility108,000 108,000
Note payable with interest at prime. Collateralized by a time deposit
of the Company earning approximately LIBOR plus 5.75%8.7%.
See description below. 34,575 34,575
Other5,400 -
2
--------- ---------
251,575 264,577Note payable with interest at 21%.
See description below. 5,655 -
---------------- ----------------
224,055 213,000
Less current portion 34,575 2
--------- ---------2,457 -
---------------- ----------------
$ 217,000221,598 $ 264,575
========= =========213,000
================ ================
In November 1997, the Companywe issued $115 million in 9.375%9.375 percent senior unsecured notes
due November 1, 2007 ("2007 Notes"), of which the Companywe subsequently repurchased $10
million at their par value for cash.value. In May 1996, the Companywe issued $125 million in 11.625%11.625
percent senior unsecured notes due May 1, 2003 ("2003 Notes"), of which the Companywe
repurchased $13$17 million at their discounted value in September 2000 and November
2000 with the issuance of 2.74.2 million common shares with a market value of $9.3
million and cash of $3.5 million plus accrued interest. 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. In August 2001, we
received the requisite consents from the holders of the 2003 Notes and 2007
Notes to amend the indentures governing the notes and the supplemental
indentures have become operative. The amendments enable Arctic Gas Company to
incur non-recourse debt of up to $77 million to fund its oil and gas development
program. At September 30, 2000, the Company was2001, we were in compliance with all covenants of the
indentures.
In August 1996,March 2001, Benton-Vinccler entered intoborrowed $12.3 million from a $50 million, long-term creditVenezuelan
commercial bank, in the form of two loans, for construction of a 31-mile oil
pipeline that will connect the Tucupita Field production facility with Morgan Guaranty Trust Companythe
Uracoa central processing unit. The first loan, with an original principal
amount of New York ("Morgan Guaranty")$6 million, bears interest payable monthly based on 90-day LIBOR plus
5 percent with principal payable quarterly for five years. The second loan, in
the amount of 4.4 billion Venezuelan Bolivars (approximately $6.3 million),
bears interest payable monthly based on a mutually agreed interest rate
determined quarterly or a six-bank average published by the central bank of
Venezuela. The interest rate for the quarter ending September 2001 was 21
percent with an effective interest rate of 7.8 percent taking into account
exchange rate gains resulting from devaluation of the Bolivar during the
quarter. Principal on the second loan is payable quarterly for five years
beginning in September 2001. The loans provide for certain limitations on
dividends, mergers and sale of assets. At September 30, 2001, we were in
compliance with all covenants of the loans.
LIQUIDITY
As a result of our substantial leverage and disappointing financial results
prior to repay2000, our equity and public debt values have eroded significantly. In
order to effectuate the balance outstanding under a short-term credit facilitychanges necessary to restore our financial flexibility
and to repayenhance our ability to execute a viable strategic plan, we began
undertaking several significant actions in 2000, including:
- - hiring a new President and Chief Executive Officer, a new Senior Vice
President and Chief Financial Officer and a new Vice President and General
Counsel;
- - reconstituting our Board of Directors with industry executives with proven
experience in oil and natural gas operations, finance and international
operations;
- - redefining our strategic priorities to focus on value creation;
- - initiating capital conservation steps and financial transactions, including
the repurchase of some of our outstanding senior notes, designed to
de-leverage the Company and improve our cash flow for reinvestment;
- - undertaking a comprehensive study of our core Venezuelan asset to attempt
to enhance the value of its production to ultimately increase cash flow and
potentially extend its productive life;
11
- - pursuing means to accelerate the commercial development of our Russian
assets;
- - seeking relief from certain advancesrestrictive provisions of our debt instruments;
and
- - implementing a plan designed to reduce general and administrative costs at
our corporate headquarters by $3 to 4 million, or approximately 50 percent,
and to transfer geological and geophysical activities to our overseas
offices.
We continue to aggressively explore means by which to maximize stockholder
value. We believe that we possess significant producing properties in Venezuela
which have yet to be optimized and valuable unexploited acreage in Venezuela and
Russia. In fact, we believe the seven new wells drilled in the South
Tarasovskoye Field since July 2001 significantly increase the value of our
Russian properties and we are reviewing alternatives to maximize their value.
These alternatives include accelerating the Russian development program and the
potential sale of all or part of the Russian assets. However, the intrinsic
value of our assets is burdened by a heavy debt load and constraints on capital
to further exploit such opportunities.
Therefore, we, with the advice of our financial and legal advisers, after having
conducted a comprehensive review to consider our strategic alternatives,
initiated a process in May 2001 intended to effectively extend the maturity of
the senior notes due May 1, 2003 by exchanging new 13.125 percent senior notes
due December 2007 plus warrants to purchase shares of our common stock for each
of the 2003 Notes. While we believe the terms of the exchange offer made to the
holders of the 2003 Notes were in the best interest of the noteholders and other
Benton stakeholders, the majority of the noteholders would not exchange their
notes for notes of a longer maturity on economic terms which were acceptable to
us. As a result, the exchange offer was withdrawn in July 2001. In August 2001,
we solicited and received the requisite consents from the Company.holders of both the
2003 Notes and the 2007 Notes to amend certain covenants in the indentures
governing the notes to enable Arctic Gas Company to incur nonrecourse debt of up
to $77 million to fund its oil and gas development program. As an incentive to
consent, we offered to pay each noteholder an amount in cash equal to $2.50 per
$1,000 principal amount of notes held for which executed consents were received.
The credit facility is
collateralizedtotal amount of consent fees paid to the consenting noteholders was $0.3
million, which has been included in full bygeneral and administrative expenses.
Additionally, we have implemented a time depositplan designed to reduce general and
administrative costs at our corporate headquarters and to transfer geological
and geophysical activities to our overseas offices in Maturin, Venezuela and in
Western Siberia and Moscow, Russia. We continue to evaluate other strategic
alternatives including, but not limited to, selling all or part of our existing
assets in Venezuela and Russia, or the sale of the Company, bears interest at prime
and matures in August 2001. The Company receives interest on its time deposit
and a security fee on the outstanding principalCompany. However, no
assurance can be given that any of the loan, for a combined
totalthese steps can be successfully completed or
that we ultimately will determine that any of approximately LIBOR plus 5.75%. The loan arrangement contains no
restrictive covenants and no financial ratio covenants. In 1999, the balance
under this facility was reduced to $34.6 million.
LIQUIDITYthese steps should be taken.
As a result of the decline in oil prices, the Company instituted in 1998, and
continued in 1999 we instituted a capital
expenditure program to reduce expenditures to those that the Companywe believed were
necessary to maintain current producing properties. In the second half of 1999,
oil prices increased substantially, and
the Company concluded an analysis of its strategic alternatives.recovered substantially. In December 1999, the Companywe entered into
incentive-based development alliance agreements with Schlumberger and Helmerich
& Payne as part of itsour plans to resume development of the South Monagas Unit in
Venezuela (see Note 8). During 2000, we drilled 26 new oil wells and re-entered
2 oil wells in the Uracoa Field under the alliance agreements utilizing
Schlumberger's technical and engineering resources. In January 2001, we
suspended the development drilling program until the second half of 2001 in
order to thoroughly review all aspects of operations and to integrate field
performance to date with revised computer simulation modeling and improved well
completion technology. In August 2001, drilling re-commenced in the Uracoa Field
under the alliance agreement with Schlumberger. We anticipate drilling a total
of eight new wells in Uracoa and then six to ten wells in the Tucupita Field
commencing in late 2001 or early 2002. In August 2001, Benton-Vinccler signed an
agreement to amend the alliance with Schlumberger. The amended long-term
incentive-based alliance continues to provide incentives intended to improve
initial production rates of new wells and to increase the average life of the
downhole pumps at South Monagas. In addition, Schlumberger has agreed to provide
drilling and completion services for new wells utilizing fixed lump-sum pricing.
We chose not to renew the alliance with Helmerich & Payne and have entered into
a standard drilling contract with Flint South America, Inc. ("Flint"). In
September 2001, we completed the reservoir simulation study of the Uracoa Field
and expect to complete a revised field development plan, incorporating the
results of this study, in the early part of 2002.
While no assurance can be given, the Companywe currently believesbelieve that itswe have sufficient
flexibility with our discretionary capital expenditures and investments in and
advances to affiliates that our capital resources and liquidity will be adequate
to fund its planned capital
expenditures, investments in and advances to affiliates, andour semiannual interest payment obligations for the next twelve (12)12 months. This
expectation is based upon anticipatedour current estimate of projected price levels,
production and the availability of short-term working capital facilities of up
to $15$11 million during the time periods between the submission of quarterly
invoices to PDVSA by Benton-Vinccler and the subsequent payments of these
invoices by PDVSA. Actual results could be materially affected if there is aare
significant decreaseadditional decreases in either pricecrude oil prices or decreases in production
levels related to the South Monagas Unit. Future cash flows are subject to a
number of variables including, but not limited to, the level of production and
prices, as well as various economic conditions that have historically affected
the oil and natural gas business. Prices for oil are subject to fluctuations in
response to changes in supply, market uncertainty and a variety of factors
beyond our control. We estimate that a change in the Company's control.price of oil of $1.00 per
barrel would affect cash flow from operations by approximately $0.8 million
based on our third quarter production rates and cost structure.
12
In October 2000, aan uncommitted short-term working capital facility of 8 billion
Bolivars (approximately $11.5$11 million) was made available to Benton-Vinccler by a
Venezuelan commercial bank. The credit facility bears interest at fixed rates
for 30-day periods, is guaranteed by the Companyus and contains no restrictive or financial
ratio covenants. The current interest rate on the facility is 18%. The
CompanyIn January 2001, Benton-Vinccler borrowed 55.4 billion Bolivars
(approximately $7.2$7.7 million) under this facility, which it expects to repayrepaid in February
2001. Again in October 2001, we borrowed 5 billion Bolivars (approximately $6.7
million) under the facility which will be repaid in November 2000.
12
12
The Company has2001 after the
receipt of the third quarter payment from PDVSA. At September 30, 2001, the
facility had no outstanding balance.
We have significant debt principal obligations payable in 2003 and 2007. During
September 2000, the Companywe exchanged 2.7 million shares of itsour common stock, plus
accrued interest, for $8 million face value of its 11 5/8%our 11.625 percent senior notes
due in 2003 and purchased $5 million face value of itsour 2003 senior notes for
cash of $3.5 million plus accrued interest. Additionally, in November 2000, the Companywe
exchanged 1.41.5 million shares of itsour common stock, plus accrued interest, for an
aggregate $4 million face value of its 11 5/8%our 11.625 percent senior notes due in 2003.
The Company anticipates continuing toWe may exchange itsadditional common stock or cash for senior notes at a
substantial discount to their face value if available on economic terms and
subject to certain limitations. Under the rules of the New York Stock Exchange,
the common stockholders would need to approve the issuance of an aggregate of
more than 5.9 million shares of common stock in exchange for senior notes. The
effect on existing shareholdersstockholders of further issuances in excess of 5.9 million
shares of common stock in exchange for senior notes will be to materially dilute
the existing shareholdersstockholders if material portions of the senior notes are
exchanged. The dilutive effect on the common stockholders would depend upon a
number of factors, the primary ones being the number of shares issued, the price
at which the common stock is issued and the discount on the senior notes
exchanged.
If the Company'sour future cash requirements are greater than itsour financial resources, the Company intendswe
intend to develop sources of additional capital and/or reduce itsour cash
requirements by various techniques including, but not limited to, the pursuit of
one or more of the following alternatives: restructure the existing debt; reduce
itsthe total debt outstanding by exchanging debt for equity or by repaying debt
with proceeds from the sale of assets, each on appropriate terms; manage the
scope and timing of our capital expenditure programs,expenditures, substantially all of which are
within itsour discretion; reduce its operating and administrative expenditures; form strategic joint ventures or alliances with financial or other
industry partners; sell property
interests;all or a portion of our existing assets, including
interests in our assets; issue debt or equity securities or otherwise raise
additional funds or, merge or combine with another entity;entity or issue debt or equity
securities.sell the Company.
There can be no assurance that any of the alternatives, or some combination
thereof, will be available or, if available, will be on terms acceptable to the Company.us.
NOTE 4 - COMMITMENTS AND CONTINGENCIES
On February 17, 1998, the WRT Creditors Liquidation Trust ("WRT Trust") filed
suit in the United States Bankruptcy Court, Western District of Louisiana
against the
Companyus and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil &
Gas of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to
Tesla Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties and that it paid a
price in excess of the fair value of the property. A trial commenced on May 1,
2000 andthat concluded at the end of August 2000. Post Trial Briefs have been filed2000, and post trial briefs were filed.
In August 2001, a favorable decision is expectedwas rendered in the next several months. The Company believes that
this case lacks meritBOGLA's favor denying any
and that the probability of an unfavorable outcomeall relief to the Company is unlikely.
InWRT Trust. The WRT Trust has stated that it would appeal
the normal coursedecision prior to the end of its business, the Company may periodically become
subject to actions threatened or brought by its investors or partners2001; however, we believe that any such appeal
would result in connectionan outcome consistent 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.court's prior decision.
In May 1996, the Companywe entered into an agreement with Morgan Guaranty that provided for
an $18 million cash collateralized 5-yearfive-year letter of credit to secure the Company'sour
performance of the minimum exploration work program required inon the Delta Centro
Block in Venezuela. As a result of expenditures made related to the exploration
work program, the letter of credit hashad been reduced to $7.7 million. 13
13
In November 1997, the Company entered intoJanuary
2001, we and our bidding partners reached an agreement with Morgan Guaranty
which providedto terminate the
remainder of the exploration work program in exchange for a $1 million cash collateralized 2-yearthe unused portion of
the standby letter of credit which was extendedof $7.7 million.
In March 2001, Benton-Vinccler submitted a claim to November 2000,PDVSA for approximately $16
million seeking recovery for the value of oil quality adjustments made by PDVSA
to secure its obligations under the first
exploration phase ofoil delivered by Benton-Vinccler since production began at the South
Monagas Unit in 1993. We believe that we have a Production Sharing Agreement ("PSA")contractual basis for the claim
as the oil quality adjustments are not in conformity with Jordan's
Natural Resources Authority ("NRA") (see Note 11). At the May 17, 2000
expirationdelivery
specifications set out in the operating service agreement. PDVSA has agreed to
research and reconstruct their computer records from date of first delivery in
order to research the PSA,claim. Any compensation from PDVSA related to this matter
will be recorded in the Company had not completed its obligation underperiod in which PDVSA confirms our claim.
Benton-Vinccler produces natural gas associated with the first exploration phaseproduction of oil in
the South Monagas Unit. A portion of the agreement. Asnatural gas is consumed as fuel for
field operations and the remaining natural gas is re-injected. Benton-Vinccler
has been in
13
discussions with PDVSA for several years regarding the appropriate amount to pay
PDVSA for the natural gas consumed as fuel and has, to date, recorded a
result,liability based on rates previously charged by PDVSA. It is uncertain when a
final agreement regarding the NRA collectedpayment for natural gas consumed as fuel will be
reached or if the amounts accrued will reflect the ultimate settlement of the
obligation.
In the normal course of our business, we may periodically become subject to
actions threatened or brought by our investors or partners in connection with
the operation or development of our properties or the sale of securities. We are
also subject to ordinary litigation that is incidental to our business. None of
these matters are currently expected to have a material adverse effect on the letterour
financial position, results of credit in August 2000.
The Company hasoperations or liquidity.
We have employment contracts with fourthree senior management personnel which
provide for annual base salaries, bonus compensation and various benefits. The
contracts provide for the continuation of salary and benefits for the respective
terms of the agreements in the event of termination of employment without cause.
These agreements expire at various times from December 31, 20002002 to July 9, 2003.
The Company has also entered into employment agreements with three individuals,
which provide for certain severance payments in the event of a change of control
of the Company and subsequent termination by the employees for good reason.
The Company has entered into various exploration and development contracts in
various countries which require minimum expenditures, some of which required
that the Company secure its commitments by providing letters of credit (see
Notes 8 and 11). The Company has alsoWe have entered into equity acquisition agreements in Russia which call for the Companyus
to provide or arrange for certain amounts of credit financing in order to remove
sale and transfer restrictions on the equity acquired or to maintain ownership
in such equity (see Note 7).
The Company leasesWe lease office space in Carpinteria, California under two long-term lease
agreements that are subject to annual rent adjustments based on certain changes
in the Consumer Price Index. TheWe lease for 17,500 square feet of space in a building
that we no longer used by the Companyoccupy under a lease agreement that expires in December 2004;
all of thethis office space has been subleased for rents that approximate the Company'sour lease
costs. Additionally, the Company leaseswe lease 51,000 square feet of space in a separate
building formerly
used as our headquarters office in Carpinteria, California, for approximately
$76,000$79,000 per month under a lease agreement that expires in August 2013; the Company has2013. We have
subleased 31,000 square feet of office space in this building for approximately
$50,000$51,000 per month. We are currently evaluating terminating the building lease
and estimate the cost to do so will be approximately $0.8 million. In July 2001,
we entered into a three-year lease agreement for 8,600 square feet of office
space in a building in Houston, Texas for approximately $11,000 per month.
We recently received a letter from the New York Stock Exchange ("NYSE")
notifying us that we have fallen below the continued listing standards of the
NYSE. These standards include a total market capitalization of at least $50
million over a 30-day trading period and stockholders' equity of at least $50
million. According to the NYSE's notice, our total market capitalization over
the 30 trading days ended October 17, 2001, was $48.2 million, and our
stockholders' equity as of June 30, 2001, was $14.3 million ($16 million at
September 30, 2001). In accordance with the NYSE's rules, we intend to submit a
plan to the NYSE by mid-December detailing how we expect to reestablish
compliance with the listing criteria within the next 18 months. The NYSE is
expected to respond to the plan within 45 days after it is submitted. Because of
our ongoing efforts to implement our strategic plan for improvements and to
evaluate alternatives to restore our financial flexibility, we believe that we
will be able to meet the NYSE's continued listing standards in the future. These
alternatives include continued cost reductions, production enhancements, selling
all or part of our assets in Venezuela and/or Russia, restructuring the debt or
some combination of these alternatives. We may also recommend selling the
Company. However, we cannot give any assurance that any of these steps can be
successfully completed or that we ultimately will determine that any of these
steps should be taken. Failure to meet the NYSE criteria may result in the
delisting of our common stock on the NYSE. As a result, an investor may find it
more difficult to dispose or obtain quotations or market value of our common
stock, which may adversely affect the marketability of our common stock.
However, given our strategic plan referenced above, we are optimistic that we
will be able to meet the NYSE requirements in the future and consequently, do
not expect our stock to be delisted.
14
NOTE 5 - TAXES
TAXES OTHER THAN ON INCOME
The CompanyBenton-Vinccler pays municipal taxes of approximately 2.75% on3.6 percent of operating
fee revenues it receives for production from the South Monagas Unit. The Company hasWe have
incurred the following Venezuelan municipal taxes and other taxes (in
thousands):
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
2001 2000 2001 2000
----------- ----------- ----------- ------------
Venezuelan municipal taxes $ 1,015 $ 817 $ 3,535 $ 2,463
Severance and production taxes - 24 - 24
Franchise taxes 29 33 89 106
Payroll and other taxes 199 490 745 867
----------- ----------- ----------- ------------
$ 1,243 $ 1,364 $ 4,369 $ 3,460
=========== =========== =========== ============
Venezuelan municipal taxes for the nine months ended September 30, 2000 1999
------------- ------------
Venezuelan Municipal Taxes $ 2,463 $ 1,580
Severance2001 include
an adjustment of $0.8 million due to a change in tax rates at the South Monagas
Unit in Venezuela. In August 2001, Benton-Vinccler entered into settlement
agreements with two adjacent municipalities regarding the proper allocation of
oil production between the two municipalities and Production Taxes 24 -
Franchise Taxes 106 117
Payrollthe resulting municipal taxes
due for the years 1996 through 2000. The settlement agreements allow
Benton-Vinccler to recover over-payment of municipal taxes from one municipality
and Other Taxes 867 755
-------- -------
$ 3,460 $ 2,452
======== =======requires additional municipal tax payments over a two-year period to the
second municipality. As of September 2001, the amount of the municipal tax
liability was $2.6 million, $1.5 million reflected as accrued expenses and $1.1
million reflected as other liabilities, and the amount of the municipal tax
receivable was $2.0 million.
TAXES ON INCOME
At December 31, 1999, the Company2000, we had, for federal income tax purposes, operating loss
carryforwards of approximately $100$103 million expiring in the years 2003 through
2019.2020. If the carryforwards are ultimately realized, approximately $13 million
will be credited to additional paid-in capital for tax benefits associated with
deductions for income tax purposes related to stock options. During the nine
months ended September 30, 2000, the Company2001, we recorded deferred tax assets generated from
current period operating losses and a valuation allowance of $4.8$4.7 million.
The Company doesWe do not provide deferred income taxes on undistributed earnings of
international consolidated subsidiaries for possible future remittances as all
such earnings are reinvested as part of the Company'sour ongoing business.
14
1415
NOTE 6 - OPERATING SEGMENTS
The CompanyWe regularly allocatesallocate resources to and assessesassess the performance of itsour 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 USA operating segments are derived primarily from the production
and sale of oil and natural gas. Operations included under the heading "USA and
Other" include corporate management, exploration and production activities, cash
management and financing activities performed in the United States and other
countries which do not meet the requirements for separate disclosure. All
intersegment revenues, expenses and receivables are eliminated in order to
reconcile to consolidated totals. Corporate general and administrative and
interest expenses are included in the USA and Other segment and are not
allocated to other operating segments.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
SEPTEMBER 30,
---------------------- -------------------------------------------------------------- ---------------------------------------
(in thousands) 2001 2000 19992001 2000
1999
--------- --------- --------- ------------------------- ----------------- ---------------- ----------------
OPERATING SEGMENT REVENUES
Oil and natural gas sales:
Venezuela $ 37,796 $ 24,565 $ 101,189 $ 61,006$31,370 $37,796 $98,552 $101,189
United States and other -- 176 -- 327
--
--------- --------- --------- ----------------------- ----------------- ---------------- ----------------
Total oil and gas sales 31,370 37,972 24,56598,552 101,516
61,006
--------- --------- --------- ----------------------- ----------------- ---------------- ----------------
OPERATING SEGMENT INCOME (LOSS)
Venezuela 6,056 7,964 4,80216,949 20,011
2,080
Russia 2,557 1,821 (266)5,462 2,695 459
United States and other (6,881) (817) (18,665)(19,556) (11,005)
(32,887)
--------- --------- --------- ----------------------- ----------------- ---------------- ----------------
Net income (loss) $ 8,968 $ (14,129) $ 11,701 $ (30,348)
========= ========= ========= =========
$1,732 $8,968 $2,855 $11,701
============== ================= ================ ================
SEPTEMBER 30, DECEMBER 31,
2001 2000
1999
------------- ------------
----------------- -----------------
OPERATING SEGMENT ASSETS
Venezuela $ 166,765 $ 124,942$181,529 $166,462
Russia 73,212 61,989100,028 78,406
United States and other 168,632 188,000
--------- ---------
Sub-total 408,609 374,931127,832 156,780
-------------- -----------------
Subtotal 409,389 401,648
Intersegment eliminations (91,398) (98,620)
--------- ---------(100,248) (115,201)
-------------- -----------------
Total assets $ 317,211 $ 276,311
========= =========$309,141 $286,447
============== =================
15
1516
NOTE 7 - RUSSIAN OPERATIONS
GEOILBENT
LTD.
The Company owns 34%We own 34 percent of Geoilbent, Ltd., a Russian limited liability company formed in
1991 to develop, producethat develops, produces and marketmarkets crude oil from the North Gubkinskoye,
FieldPrisklonovoye and South Tarasovskoye Fields in the West Siberia region of
Russia. The Company'sOur investment in Geoilbent is accounted for using the equity method.
Sales quantities attributable to Geoilbent for the nine months ended June 30,
2001 and 2000 and 1999 were 3,136,8103,751,788 barrels and 3,149,1033,136,810 barrels, respectively. Prices
for crude oil for the nine months ended June 30, 2001 and 2000 averaged $19.06
and 1999 averaged $15.70 and $5.89 per barrel, respectively. Depletion expense attributable to Geoilbent
for the nine months ended June 30, 2001 and 2000 was $2.65 and 1999 was $2.20 and $2.27 per barrel,
respectively. SummarizedUnaudited financial information for Geoilbent follows (in
thousands). All amounts represent 100%100 percent of Geoilbent.
STATEMENTS OF INCOME:
THREE MONTHS ENDED JUNE 30, NINE MONTHS ENDED
JUNE 30, ------------------------------ ------------------------------JUNE 30,
---------------------------------- -------------------------------
2001 2000 19992001 2000
1999
--------- --------- -------- ---------------------- ------------- -------------- -------------
Revenues $24,191 $20,748 $71,495 $49,270
------------- ------------- -------------- -------------
Oil sales $24,191 20,748 $ 6,933 $71,495 49,270
$ 18,546
-------- -------- -------- --------
20,748 6,933 49,270 18,546
-------- -------- -------- --------------------- ------------- -------------- -------------
Expenses
Operating expenses 2,770 2,669 1,6797,572 6,941 3,433
Depletion, depreciation and amortization 3,538 2,418 2,2219,942 6,896 7,168
General and administrative 1,406 1,216 6033,581 2,357 1,718
Taxes other than on income 5,703 4,032 1,71120,496 8,733
5,017
-------- -------- -------- --------------------- ------------- -------------- -------------
13,417 10,335 6,21441,591 24,927
17,336
-------- -------- -------- --------------------- ------------- -------------- -------------
Income from operations 10,774 10,413 71929,904 24,343 1,210
Other Non-Operating Income (Expense)
Other income (expense) 178 129 472652 (245) 1,197
Interest expense (1,602) (1,610) (370)(5,574) (5,187) (2,368)
Net gain (loss) on exchange rates 44 (137) (308)482 (517)
4,476
-------- -------- -------- --------------------- ------------- -------------- -------------
(1,380) (1,618) (206)(4,440) (5,949)
3,305
-------- -------- -------- --------------------- ------------- -------------- -------------
Income before income taxes 9,394 8,795 51325,464 18,394 4,515
Income tax expense 2,053 1,927 6095,393 4,318
297
-------- -------- -------- --------------------- ------------- -------------- -------------
Net income (loss)$ 7,341 $ 6,868 $20,071 $14,076
============= ============= ============== =============
17
BALANCE SHEETS:
JUNE 30, SEPTEMBER 30,
2001 2000
------------ ------------
Current assets:
Cash and cash equivalents $ (96)1,763 $ 14,0762,133
Restricted cash 11,364 12,361
Accounts receivable
Trade and other 3,100 2,937
Accrued oil revenue 1,408 3,881
Inventory - materials 15,774 7,955
Prepaid expenses and other 3,865 803
------------ ------------
Total current assets 37,274 30,070
Other assets 1,148 1,407
Property and equipment
Oil and gas properties (full cost method) 239,449 212,308
Accumulated depletion and depreciation (60,439) (50,496)
------------ ------------
179,010 161,812
------------ ------------
Total assets $217,432 $193,289
============ ============
Current liabilities:
Accounts payable, trade and other $ 4,218
======== ======== ======== ========17,152 $ 14,562
Accrued expenses 4,547 4,327
Accrued interest payable 2,636 1,503
Income taxes payable 2,056 1,853
Short-term borrowings 5,192 3,866
Current portion of long-term debt 15,955 10,455
------------ ------------
Total current liabilities 47,538 36,566
Long-term debt 31,100 38,000
Commitments and contingencies - -
Equity
Contributed capital 82,518 82,518
Retained earnings 56,276 36,205
------------ ------------
138,794 118,723
------------ ------------
Total liabilities and stockholders' equity $217,432 $193,289
============ ============
JUNE 30, SEPTEMBER 30,
2000 1999
--------- -------------
Current assets $ 29,854 $ 25,699
Other assets 153,568 139,488
Current liabilities 17,971 10,276
Other liabilities 50,718 54,254
Net equity 114,733 100,657
The European Bank for Reconstruction and Development ("EBRD") and International
Moscow Bank ("IMB") together have agreed to lend up to $65 million to Geoilbent,
based on Geoilbent achieving certain reserve and production milestones, under
parallel reserve-based loan agreements. Under these loan agreements, the Company
and other shareholders of Geoilbent have significant management and business
support obligations. Each shareholder is jointly and severally liable to EBRD
and IMB for any losses, damages, liabilities, costs, expenses and other amounts
suffered or sustained arising out of any breach by any shareholder of its
support obligations. The loans bear an average annual interest rate of 15%15
percent payable on January 27 and July 27 each year. Principal payments will beare due
in varying installments on the semiannual interest payment dates beginningwhich began on
January 27, 2001 and ending
byend on 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, 16
16
dividends, mergers
and sales of assets. Geoilbent began borrowing under these facilities in October
1997 and hashad borrowed a total of $48.5 million through JuneDecember 31, 2000. The
four-year loan amortization period began in January 2001, and through September
30, 2000.2001 Geoilbent has repaid $10.5 million. The proceeds from the loans are beingwere
used by Geoilbent to develop the North Gubkinskoye and Prisklonovoye Fields in
West Siberia, Russia.
18
During 1996 and 1997, the Companywe 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 ratified an agreement to reimburse the
Companyus for $2.6
million of such costs, which were then included in accounts receivable. However, due to Geoilbent's need for oil and gas investment andDuring
2000, Geoilbent paid the declining prices for crude oil, in the second quarter of 1998 the Company agreed
to defer payment of those reimbursements. The Company received $1.0 million in
June 2000, $1.0 million in July 2000 and expects to receive $0.6 million in the
first quarter of 2001 from Geoilbent as reimbursement of such costs.accounts receivable.
In October 1995, Geoilbent entered into an agreement with Morgan Guaranty for a
credit facility under which the Company provideswe provide 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, whichever is selected at the
time a loan is made. In conjunction with Geoilbent's reserve-based loan agreements with
the EBRD and IMB, repayment of the credit facility was subordinated to payments
due to the EBRD and IMB and, accordingly, the credit facility was reclassified
from current to long-term in 1998. TheIn May 2001, Geoilbent entered into an
agreement with IMB to borrow $3.3 million to repay the Morgan credit facility
contains no restrictive covenants and, no financial ratio covenants. At September
30, 2000, $3.1as a result, our cash collateral was returned. The loan from IMB is due on
November 15, 2002, bears interest at LIBOR plus 6 percent and requires quarterly
payments of principal and interest of approximately $0.6 million was outstanding under the credit facility.beginning in
August 2001.
Excise, pipeline and other tariffs and taxes continue to be levied on all oil
producers and certain exporters, including an oil export tariff that increaseddecreased
to 3422 Euros per ton (approximately $3.80$2.70 per barrel) on November 1, 2000March 18, 2001 from 1548
Euros per ton in 1999.January 2001. The Company isexport tariff increased to 30.5 Euros per ton
(approximately $3.64 per barrel) in July 2001. We are unable to predict the
impact of taxes, duties and other burdens for the future for itsour Russian
operations.
ARCTIC GAS COMPANY
In April 1998, the Companywe signed an agreement to earn a 40%40 percent equity interest in
Arctic Gas Company, formerly Severneftegaz.Company. 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 837,000794,972 acres
within and adjacent to the Urengoy Field, Russia's largest producing natural gas
field. Under the terms of a Cooperation Agreement between the Company andwith Arctic Gas, the Companywe will earn
a 40%40 percent equity interest in exchange for providing the initial capital
needed to achieve economic self-sufficiency through its own oil and gas
production. The Company'sOur capital commitment will be in the form of a credit facility of
up to $100 million for the project, the terms and timing of which have yet to be
finalized. Pursuant to the Cooperation Agreement, the Company haswe have received voting shares
representing a 40%40 percent ownership in Arctic Gas that contain restrictions on
their sale and transfer. A Share Disposition Agreement provides for removal of
the restrictions as disbursements are made under the credit facility. As of
September 30, 2000,
the Company2001, we had loaned $18.3$28.5 million to Arctic Gas pursuant to an
interim credit facility, with interest at LIBOR plus 3%,3 percent, and had earned
the right to remove restrictions from shares representing an approximate 7%11
percent equity interest. From December 1998 through April 2000, the CompanySeptember 2001, we purchased
shares representing an additional 20%28 percent equity interest not subject to any
sale or transfer restrictions. The CompanyWe owned a total of 60%68 percent of the outstanding
voting shares of Arctic Gas as of September 30, 2000,2001, of which approximately 27%39
percent were not subject to any restrictions.
The Company accountsWe account for itsour interest in Arctic Gas using the equity method due to the
significant influence it exerciseswe exercise over the operating and financial policies of
Arctic Gas. The Company'sOur share in the equity losses of Arctic Gas were $0.1$0.5 million and $0.7
million for the three and nine month periods ended June 30, 2001 and 2000, respectively.
The Company's share inFor the equity losses of Arctic
Gas were $0.1 million and $0.2 million for the three and nine month periodsmonths ended June 30, 1999, respectively. For the three months ended September 30,2001 and 2000, and 1999 the Companywe had a weighted-average
equity interest of 27%29 percent and 20%,
respectively, not subject to any sale or transfer restrictions. For the nine
months ended September 30, 2000 and 1999 the Company had a weighted-average
equity interest of 26% and 18%,26 percent, respectively, not subject to any
sale or transfer restrictions. Certain provisions of Russian corporate law would
effectively require minority shareholder consent to enter into new agreements
between the Companyus and Arctic Gas, or change any terms in any existing agreements
between the two partners such as the Cooperation Agreement and the Share
Disposition Agreement, including the conditions upon which the restrictions on
the shares could be removed.
17
1719
Arctic Gas began selling oil in June 2000. Sales quantities attributable to
Arctic Gas for the nine months ended June 30, 2001 were 417,612 barrels, prices
for crude oil for the nine months ended June 30, 2001 averaged $16.73 per barrel
and depletion expense attributable to Arctic Gas for the nine months ended June
30, 2001 was $1.37 per barrel.
Summarized unaudited financial information for Arctic Gas follows (in
thousands). All amounts represent 100%100 percent of Arctic Gas.
STATEMENTS OF OPERATIONS:
THREE MONTHS ENDED JUNE 30, NINE MONTHS ENDED JUNE 30,
--------------------------- -------------------------------------------------------------- --------------------------------
2001 2000 19992001 2000
1999
--------- -------- --------- -------------------- -------------- ------------- ------------
Oil Sales $ 3,547 $ 1,773 $ --6,988 $ 1,773 --
Expenses
Operating expenses (380) 867 --1,855 1,157
DepreciationDepletion, depreciation and amortization 420 45 22733 237 63
General and administrative 790 600 4242,086 1,452 2,562
Taxes other than on income 1,026 391 172,799 562
45
------- ------- ------- -------------------- -------------- ------------ ------------
1,856 1,903 4637,473 3,408
2,670
------- ------- ------- -------------------- -------------- ------------ ------------
Income (loss) from operations 1,691 (130) (485) (1,635)
Other Non-Operating Income (Expense)
Net gain (loss) on exchange rates (23) 2 (64)(305) (235) 328
Interest expense (461) (346) (221)(1,226) (836)
(576)
------- ------- ------- -------------------
------------- -------------- ------------
(484) (344) (285)(1,531) (1,071)
(248)
------- ------- ------- -------
Loss------------- -------------- ------------ ------------
Income (loss) before income taxes 1,207 (474) (748)(2,016) (2,706) (2,918)
Income tax expense -- -- -- --
------- ------- ------- -------(benefit) - - (189) -
------------- -------------- ------------ ------------
Net lossincome (loss) $ 1,207 $ (474) $ (748) $(2,706) $(2,918)
======= ======= ======= =======(1,827) $ (2,706)
============= ============== ============ ============
BALANCE SHEET DATA:
JUNE 30, SEPTEMBER 30,
2001 2000
------------- -------------------
Current assets $ 4,945 $ 1,205
Other assets 13,859 10,120
Current liabilities 33,038 23,955
Net deficit (14,234) (12,630)
JUNE 30, SEPTEMBER 30,
2000 1999
---------- -------------
Current assets $ 3,353 $ 1,513
Other assets 9,531 5,043
Current liabilities 25,167 18,068
Net deficit (12,283) (11,512)
NOTE 8 - VENEZUELA OPERATIONS
On July 31, 1992, the Companywe and itsour partner, Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), signed an operating service agreement to reactivate
and further develop three Venezuelan oil fields with Lagoven, S.A., then one of
three exploration and production affiliates of the national oil company,
Petroleos de Venezuela, S.A. ("PDVSA") which have subsequently all been combined into
PDVSA Petroleo y Gas, S.A. (all such parent, subsidiary and affiliated entities
hereinafter referred to as "PDVSA"). The operating service agreement covers the
Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit (the
"Unit"). Under the terms of the operating service agreement, Benton-Vinccler,
C.A. ("Benton-Vinccler"), a corporation owned 80%80 percent by the
Companyus and 20%20 percent by
Vinccler, is a contractor for PDVSA and is responsible for overall operations of
the Unit, including all necessary investments to reactivate and develop the
fields comprising the Unit. Benton-Vinccler receives an operating fee in U.S.
dollars deposited into a U.S. commercial bank account for each barrel of crude
oil produced (subject to periodic adjustments to reflect changes in a special
energy index of the U.S. Consumer Price Index) and is reimbursed according to a
prescribed formula in U.S. dollars for its capital costs, provided that such
operating fee and cost recovery fee cannot exceed the maximum dollar amount per
barrel set forth in the agreement (which amount is periodically adjusted to
reflect changes in the average of certain world crude oil prices). The
Venezuelan government maintains full ownership of all hydrocarbons in the
fields. In August 1999, Benton-Vinccler sold its power generation facility locatedCurrently, we are in discussions with PDVSA regarding the Uracoa Field ofappropriate
amount to
20
pay for natural gas produced from the South Monagas Unit and used as fuel in
Venezuela for $15.1 million.
Concurrently with the sale, Benton-Vinccler entered into a long-term power
purchase agreement with the purchaser of the facility to provide for the
electrical needs of the field throughout the remaining term of theBenton-Vinccler's operations as well as other operating service agreement. Benton-Vinccler used the proceeds from the sale to repay
indebtedness that was collateralized by a time deposit of the Company. Permanent
repayment of a portion of the loan allowed the Company to reduce the cash
collateral for the loan thereby making such cash available for working capital
needs.issues.
In December 1999, the Companywe entered into alliancesagreements with Schlumberger and Helmerich &
Payne to further develop the South Monagas Unit pursuant to a long-term
incentive-based development program. The alliance partners haveSchlumberger has agreed to financial
incentives 18
18 intended to reduce drilling costs, improve initial production rates
of new wells and to increase the average life of the downhole pumps at South
Monagas. As part of Schlumberger's commitment to the program, it provides
additional technical and engineering resources on-site full-time in Venezuela
and at the Company'sour offices in Carpinteria, California. As of September 30,December 31, 2000, 2226 new
oil wells haveand 2 re-entry oil wells had been drilled under the alliance program.
In January 2001, we suspended the development drilling program until the second
half of 2001 in order to thoroughly review all aspects of operations in order to
integrate field performance to date with revised computer simulation modeling
and improved well completion technology. In August 2001, drilling re-commenced
in the Uracoa Field under the alliance agreement with Schlumberger. We
anticipate drilling a total of eight new wells in Uracoa and then drill six to
ten wells in the Tucupita Field commencing in late 2001 or early 2002. In August
2001, Benton-Vinccler signed an agreement to amend the alliance with
Schlumberger. The amended long-term incentive-based alliance continues to
provide incentives intended to improve initial production rates of new wells and
to increase the average life of the downhole pumps at South Monagas. In
addition, Schlumberger has agreed to provide drilling and completion services
for new wells utilizing fixed lump-sum pricing. We chose not to renew the
alliance with Helmerich & Payne and have entered into a standard drilling
contract with Flint. In September 2001, we completed the reservoir simulation
study of the Uracoa Field and expect to complete a revised field development
plan, incorporating the results of this study, in the early part of 2002.
In January 1996, the Companywe and itsour bidding partners, predecessor companies acquired
over time by Burlington Resources, Inc. ("Burlington") and Anadarko Petroleum
CorportationCorporation ("Anadarko"), were awarded the right to explore and develop the
Delta Centro Block in Venezuela. The contract requiresrequired a minimum exploration
work program consisting of completing an 839 kilometera seismic survey and the drilling of three wells to the depths of 12,000 to 18,000 feet
within five years. At the time the block was tendered for international bidding,
PDVSA estimated that this minimum exploration work program would cost $60
million and required that the Companywe and the other partners each post a performance
surety bond or standby letter of credit for itsour pro rata share of the estimated
work commitment expenditures. The Company hasWe had a 30%30 percent interest in the exploration
venture, with Burlington and Anadarko each owning a 35%35 percent interest. Under the
terms of the operating agreement, which establishes the management company of
the project, Burlington is the operator of the field and, therefore, the Company
is not able to exercise control of the operations of the venture. Corporacion
Venezolana del Petroleo, S.A., an affiliate of PDVSA, has the right to obtain a
35% interest in the management company, which dilutes the voting power of the
partners on a pro rata basis. In July
1996, formal agreements were finalized and executed, and the Companywe posted an $18
million standby letter of credit, collateralized in full by a time deposit, of the Company, to
secure its 30%our 30 percent share of the minimum exploration work program (see Note
4). During 1999, the Block's first exploration well, the Jarina 1-X, penetrated
a thick potential reservoir sequence, but encountered no hydrocarbons.
In January 2001, we and our bidding partners reached an agreement with
Corporacion Venezolana del Petroleo, S.A. to terminate the contract in exchange
for the unused portion of the standby letter of credit of $7.7 million. As a
result, we included $7.7 million of restricted cash that collateralized the
letter of credit in the Venezuelan full cost pool. As of September 30, 2000, the
Company's2001, our
share of expenditures to date was $15.4 million, all of which had been
included in the Venezuela cost center, and the standby letter of credit had been
reduced to $7.7 million. The Company continues to evaluate the remaining leads
on the Delta Centro Block including their potential reserves and risk factors, although the
Block's future exploration activities and potential commerciality are uncertain.was $23.1 million.
NOTE 9 - UNITED STATES OPERATIONS
In April and May 2000, the Companywe entered into agreements with Coastline Energy
Corporation ("Coastline") for the purpose of acquiring, exploring and developing
oil and gas prospects both onshore and in the state waters of the Gulf Coast
states of Texas, Louisiana and Mississippi. Under the agreements, Coastline will
evaluate prospects in the Gulf Coast area for possible acquisition and
development by the Company.us. During the 18-month term of the exploration agreement, the Companywe
will reimburse Coastline for certain of its overhead and prospect evaluation
costs. Under the agreements, for prospects evaluated by Coastline and acquired by the Company,that we
acquire, Coastline will receive compensation based (a) on (a) oil and natural gas
production acquired or developed and (b) on the profits, if any, resulting from
the sale of such prospects. In April 2000, pursuant to the agreements, the Companywe
acquired an approximate 25%25 percent working interest in the East Lawson Field in
Acadia Parish, Louisiana. The acquisition included a 15%15 percent working interest
in two producing oil and natural gas wells. During the nine monthsyear ended September 30,December 31,
2000, the Company'sour share of the East Lawson Field production was 5,995 Bbls6,884 barrels of oil and
36,49243,352 Mcf of natural gas, resulting in income from United States oil and gas
operations of $0.3 million. In December 2000, we sold our interest in the East
Lawson Field for $0.8 million in cash. Additionally, we acquired a 100 percent
working interest in the Lakeside Exploration Prospect in Cameron Parish,
Louisiana. We farmed out 90 percent of the working interest in the prospect for
$0.5 million cash and a 16.2 percent carried interest in the first well. We
anticipate that drilling of the well will commence before December 2001. The
agreement with Coastline was terminated on August 31, 2001. However, certain
ongoing operations related to the Lakeside Exploration Prospect may be conducted
by Coastline on a consulting basis.
In March 1997, the Companywe acquired a 40%40 percent participation interest in three
California State offshore oil and gas leases ("California Leases") from Molino
Energy Company, LLC ("Molino Energy"), which held 100%100 percent 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%40 percent participation interest in the California Leases, the Companywe became the
operator of the project and agreed to pay 100%100 percent of the
21
first $3.7 million and 53%53 percent of the remainder of the costs of the first
well drilled on the block. During 1998, the 2199 #7 exploratory well was drilled
to the Gaviota anticline. Drill stem tests proved to be inconclusive or
non-commercial, and the well was temporarily abandoned for further evaluation.
In November 1998, the Companywe entered into an agreement to acquire Molino Energy's
interest in the California Leases in exchange for the release of its joint
interest billing obligations,
but the transaction has not yet been finalized.obligations. In the fourth quarter of 1999, the Companywe decided to focus
itsour capital expenditures on existing producing properties and fulfilling work
commitments associated with itsour other properties. Because the Company haswe had no firm
approved plans to continue drilling on the California Leases and the 2199 #7
exploratory well did not result in commercial reserves, the Companywe wrote off all of the
capitalized costs associated with the California Leases of $9.2 million and the
joint interest receivable of $3.1 million due from Molino Energy at December 31,
1999. However, we continue to evaluate the prospect for potential future
drilling activities.
NOTE 10 - CHINA OPERATIONS
In December 1996, the Companywe 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'sour 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 19
19
will,has, as aour wholly owned subsidiary, of the Company, continuecontinued as the
operator and contractor of WAB-21. Benton Offshore China Company has submitted
an exploration program and budget to CNOOC for 2000.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 held a petroleum contract with China National Petroleum Corporation
("CNPC") to explore and develop the deep rights in the Qingshui Block,
approximately 140,000 acres (563 square kilometers) in the delta of the Liaohe
River. Shell was the operator of the project. In July 1998, the Company paid to
Shell 50% of Shell's prior investment in the Block, which was approximately $4
million ($2 million to the Company). Pursuant to the farmout agreement, the
Company was required to pay 100% of the first $8 million of the costs for the
phase one exploration period, after which any development costs were to be
shared equally. During the first six months of 1999, the first exploratory well
on the Qingshui Block was drilled to a total depth of 4,500 meters, and two
reservoirs, the Sha-2 and Sha-3, were tested. Although hydrocarbons were
encountered during drilling of the Qing Deep 22, Benton and operator Shell
concluded in the third quarter that the well was non-commercial. As a result,
the Company elected not to continue to the second exploration phase and has
relinquished its interest in the Block. Accordingly, the Company recognized a
write-down of the capitalized cost related to the farmout agreement of $12.6
million in the third quarter of 1999.
NOTE 11 - JORDAN OPERATIONS
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company was obligated to spend $5.1 million in the first
exploration phase, which was extended to May 2000, for which it posted a $1
million standby letter of credit collateralized in full by a time deposit of the
Company. During the first quarter of 1998, the Company reentered two wells and
tested two different reservoirs. The WS-9 well tested significant, but
non-commercial amounts of gas; the WS-10 well resulted in no commercial amount
of hyrdrocarbons. Therefore, at December 31, 1998, the Company wrote down $3.7
million in capitalized costs incurred through that date related to the PSA.
During 1999, the Company incurred an additional $0.3 million in capitalized
costs, which were written off at December 31, 1999. As of the May 17, 2000
expiration date of the PSA, the Company had elected not to complete the first
exploration phase of the agreement. As a result, during the second quarter of
2000, the Company recorded a liability to the NRA for the obligation remaining
under the PSA resulting in impairment expense of $1.0 million. The NRA collected
on the letter of credit in August 2000.
NOTE 12 - RELATED PARTY TRANSACTIONS
From 1996 through 1998, the Companywe made unsecured loans to itsour then Chief Executive
Officer, A. E. Benton. Each of these loans was evidenced by a promissory note
bearing interest at the rate of 6%6 percent per annum. The Company thenWe subsequently obtained a
security interest in Mr. Benton's shares of stock, personal real estate and
proceeds from certain contractual and stock option agreements. At December 31,
1998, the $5.5 million owed to the Companyus by Mr. Benton exceeded the value of the Company'sour
collateral, due to the decline in the price of the
Company'sour stock. As a result, the Companywe
recorded an allowance for doubtful accounts of $2.9 million. The portion of the
note secured by the Company'sour stock and stock options, $2.1 million, was presented on the
Balance Sheet as a reduction from Stockholders' Equity at December 31, 1998. In
August 1999, Mr. Benton filed a Chapter 11 (reorganization) bankruptcy petition
in the U.S. Bankruptcy Court for the Central District of California, in Santa
Barbara, California. The CompanyWe recorded an additional $2.8 million allowance for
doubtful accounts for the remaining principal and accrued interest owed to the
Companyus at
June 30, 1999, and continuescontinue to record additional allowances as interest accrues
($0.40.9 million for the period July 1, 1999 to September 30, 2000)2001). Measuring the
amount of the allowances requires judgementsjudgments and estimates, and the amount
eventually realized may differ from the estimate.
In February 2000, the Companywe entered into a Separation Agreement and a Consulting
Agreement with Mr. Benton, pursuant to which the Companywe retained Mr. Benton as an
independent contractor to perform certain services for the Company.
At the same time,us. Mr. Benton has agreed
to propose a plan of reorganization in his bankruptcy case that provides for the
full repayment of the Company'sour loans to Mr. Benton, including all principal and accrued and accruing interest at the
rate of 6% per annum.him. Under the proposed plan, which the Company anticipateswe anticipate will
be submitted to the bankruptcy court in the first halffourth quarter of 2001 and
considered by the Companybankruptcy court in 2002, we will retain itsour security interest
in Mr. Benton's 600,000 shares of the
Company'sour stock and in his stock options, and in a portion of certain proceeds
of his Consulting Agreement.options. Repayment
of the Company'sour loans to Mr. Benton may be achieved through Mr. Benton's liquidation of
certain real and personal property assets;assets and a phased liquidation of Company stock
resulting from Mr. Benton's exercise of his Company stock options; and, if necessary, from the
retained interest in the portion of the Consulting Agreement's proceeds.options. The amount that we
eventually realized by therealize including Benton Oil and Gas Company stock and the timing of its
receipt of payments will depend upon the timing and results of the liquidation
of Mr. Benton's assets.
20
20For the nine months ended September 30, 2001 and 2000, we paid to Mr. Benton
$116,833 and $298,000, respectively, for services performed under the Consulting
Agreement. On May 11, 2001, the Consulting Agreement was terminated.
In May 2001, we entered into a Termination Agreement and a Consulting Agreement
with our Chairman of the Board, Michael B. Wray. Under the Termination
Agreement, Mr. Wray agreed to terminate any employment relationship or officer
position with us and any of our subsidiaries and affiliates as of May 7, 2001.
As consideration for entering into the Termination Agreement and settlement of
all sums owed to Mr. Wray for his services as director through the 2001 Annual
Meeting of Stockholders or as an employee, we paid Mr. Wray $100,000. Upon
execution of the Termination Agreement, all stock options previously granted to
Mr. Wray vested in their entirety. Additionally, under the terms of the
Consulting Agreement, Mr. BentonWray received $100,000 and will be paidprovide consulting
feesservices on matters pertaining to our business and that of $485,000 for 2000, reducing to $322,000 in 2001, $240,000 in 2002, and a
declining consulting fee for the remainder of the term which expiresour affiliates
through December 31, 2006. Mr. Benton will also be entitled to certain additional incentive
bonuses with respect to cash receipts to the Company in connection with the
operations or divestiture of Geoilbent, Ltd. and Arctic Gas. To the extent that
Mr. Benton continues to be a consultant of the Company, his unvested stock
options will continue to vest and for a period of twelve (12) months thereafter.
Mr. Benton's consulting services will relate principally to the Company's
Russian activities. During the nine month period ended September 30, 2000, the
Company paid to Mr. Benton $298,000 under the Consulting Agreement.
Also during 1997 and 1996, the Company made loans to Mr. M.B. Wray, its Vice
Chairman and Mr. J.M. Whipkey, its then Chief Financial Officer, each loan
bearing interest at 6% and collateralized by a security interest in personal
real estate. On May 11, 1999, Mr. Wray repaid the balance of principal and
interest on his loan and on April 25, 2000, Mr. Whipkey repaid the balance of
principal and interest on his loan.
In addition, loans and other receivables from other employees (including one
former employee) and a director to the Company totaled $0.2 million at September
30, 2000 and December 31, 1999.2001.
21
2122
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The Company cautionsWe caution you 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 our 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 cautionswe
caution you that important factors could cause actual results to differ
materially from those in the forward-looking statements. Such factors include
the Company'sour substantial concentration of operations in Venezuela and Russia, the
political and economic risks associated with international operations, the
anticipated future development costs for the
Company'sour undeveloped proved reserves, the
risk that actual results may vary considerably from reserve estimates, the
dependence upon the abilities and continued participation of certain of our key
employees, of the Company, the risks normally incident to the operation and development of oil
and gas properties and the drilling of oil and natural gas wells, the price for
oil and natural gas, and other risks indicateddescribed in the Company's Form 10-K for the year ended December 31, 1999
and its otherour 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 natural 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.
MANAGEMENT, OPERATIONAL AND FINANCIAL AND STRATEGIC INITIATIVES
The Company has adoptedRESTRICTIONS
As a comprehensive business strategy. The strategy
concentrates on two initiativesresult of our substantial leverage and disappointing financial results
prior to enhance shareholder value: restoring2000, our equity and public debt values have eroded significantly. In
order to effectuate the Company'schanges necessary to restore our financial flexibility
and exploitingto enhance our ability to execute a viable strategic plan, we began
undertaking several significant actions in 2000, including:
- hiring a new President and Chief Executive Officer, a new Senior Vice
President and Chief Financial Officer and a new Vice President and
General Counsel;
- reconstituting our Board of Directors with industry executives with
proven experience in oil and natural gas operations, finance and
international operations;
- redefining our strategic priorities to focus on value creation;
- initiating capital conservation steps and financial transactions,
including the Company'srepurchase of some of our senior notes, designed to
de-leverage the Company and improve our cash flow for reinvestment;
- undertaking a comprehensive study of our core assets.Venezuelan asset to
attempt to enhance the value of its production to ultimately increase
cash flow and potentially extend its productive life;
- pursuing means to accelerate the commercial development of our Russian
assets;
- seeking relief from certain restrictive provisions of our debt
instruments; and
- implementing a plan designed to reduce general and administrative
costs at our corporate headquarters by $3 to 4 million, or
approximately 50 percent, and to transfer geological and geophysical
activities to its overseas offices.
We continue to aggressively explore means by which to maximize stockholder
value. We believe that we possess significant producing properties in Venezuela
which have yet to be optimized and valuable unexploited acreage in Venezuela and
Russia. In connection with these initiativesfact, we believe the seven new wells drilled in the South
Tarasovskoye Field since July 2001 significantly increase the value of our
Russian properties and we are reviewing alternatives to maximize their value.
These alternatives include accelerating the Russian development program and the
financial challenges it faces, the
Company has retained Wasserstein Perella & Co. as its financial advisor to
assist in analyzing financial alternatives, with particular focus on
strengthening the balance sheet. Many options are being considered and analyzed,
including, among others, refinancings, alliances, cash purchasespotential sale of debt at a
discount, asset disposals and debt for equity swaps. Their initial report will
be submitted to the Board and integrated asall or part of the Russian assets. However, the intrinsic
value of our assets is burdened by a heavy debt load and constraints on capital
to further exploit such opportunities.
Therefore, we, with the advice of our financial and legal advisers, after having
conducted a comprehensive review to consider our strategic plan.
Inalternatives,
initiated a process in May 2001 intended to effectively extend the maturity of
the senior notes due May 1, 2003 by exchanging new 13.125 percent senior notes
due December 2007 plus warrants to purchase shares of our common stock for each
of the 2003 Notes. The exchange offer was withdrawn in July 2001 and in August
2001, we solicited and received the requisite consents from the holders of both
the 2003 Notes and the 2007 Notes to amend certain covenants in the indentures
governing the notes to enable Arctic Gas Company to incur nonrecourse debt of up
to $77 million to fund its oil and gas development program. As an incentive to
consent, we offered to pay each noteholder an amount in cash equal to $2.50 per
$1,000 principal amount of notes held for which executed consents were received.
The total amount of consent fees paid to the consenting noteholders was $0.3
million, which has been included in general and administrative expenses.
23
Additionally, we have implemented a plan designed to reduce general and
administrative costs at our corporate headquarters by $3-4 million, or
approximately 50 percent, and to transfer geological and geophysical activities
to our overseas offices in Maturin, Venezuela a strategic shiftand in Western Siberia and Moscow,
Russia. The reduction in general and administrative costs is being madeaccomplished
by reducing our headquarters staff and relocating our headquarters to focusHouston,
Texas from Carpinteria, California.
In June 2001, we recorded restructuring charges of $2.1 million, $0.9 million of
which are included in general and administrative expenses and $1.2 million of
which are included in depletion, depreciation and amortization. The
restructuring charges included $0.9 million for severance and termination
benefits for 27 employees, $0.8 million for the anticipated loss on maximizingsubleasing
the Carpinteria headquarters and $0.4 million for the reduction in the carrying
value of production atfixed assets that were not transferred to Houston. The implementation
of the South Monagas Unit rather than increasing production at any
cost. Asplan was substantially complete by the end of the third quarter of 2001.
We continue to evaluate other strategic alternatives including, but not limited
to selling all or part of this shift,our existing assets in Venezuela and Russia, or the
Company, with the assistance of alliance
partner Schlumberger, is reviewing all aspects of operations to integrate
revised computer field simulation models with improved completion technology.
The goal will be a new and more effective infill drilling and workover program
that is designed to deliver lower cost production in the second half of 2001. In
addition, discussions are underway with PDVSA to sell gas from the Unit.
In Russia, the Company's operating strategy for 34%-owned Geoilbent is to
continue to increase production, improve drilling and completion efficiency and
extend infrastructure. Geoilbent remains self-funding, and is positioned to
start repaying its loans from the European Bank of Reconstruction and
Development and the International Moscow Bank in January 2001. At Arctic Gas
(60%-owned), the Company has been successfully expanding production of oil and
condensate through the recompletion of existing wells, gaining operational
experience and generating attractive cash flows. The short-term strategy is to
build facilities and pipelines to optimize delivery of liquids and to start
production and sales of natural gas. The technical details, scopesale of the pipeline links and access to the Gazprom infrastructure have all been agreed
upon.
GENERAL
The Company includesCompany. However, no assurance can be given that any of these steps
can be successfully completed or that we ultimately will determine that any of
these steps should be taken.
RESULTS OF OPERATIONS
We include the results of operations of Benton-Vinccler in itsour consolidated
financial statements and reflectsreflect the 20%20 percent ownership interest of Vinccler
as a minority interest. We account for our investments in Geoilbent and Arctic
Gas are includedusing the equity method. We include Geoilbent and Arctic Gas in theour
consolidated financial statements based on a fiscal periodyear ending September 30.
ResultsAccordingly, our results of operations for the nine months ended September 30,
2001 and 2000 reflect results from Geoilbent and Arctic Gas reflectfor the three and nine month periodsmonths
ended June 30, 19992001 and 2000. The Company's investments in
Geoilbent and Arctic Gas are accounted for using the equity method.
The Company follows2000, respectively.
We follow the full-cost method of accounting for itsour investments in oil and gas
properties. The Company capitalizesWe capitalize all acquisition, exploration, and development costs
incurred. The Company accountsWe account for itsour oil and gas properties using cost centers on a
country by country basis. ProceedsWe credit proceeds from sales of oil and gas
properties are credited to the full-cost pools. Capitalizedpools if the sales do not result in a significant
change in the relationship between costs and the value of proved reserves or the
underlying value of unproved property. We amortize capitalized costs of oil and
gas properties are amortized within the cost centers on an overall unit-of-production method
using proved oil and gas reserves as audited or prepared by independent
petroleum engineers. Costs amortized includethat we amortize include:
- all capitalized costs (less accumulated amortization and impairment),;
- the estimated future expenditures (based on current costs) to be
incurred in developing proved reserves,reserves; and
- estimated dismantlement, restoration and abandonment costs (see Note 1
of Notesthe "Notes to the Consolidated Financial Statements)Statements" for additional
information).
22
22
Statement of Financial Accounting Standards No. 133 ("SFAS 133"), as amended,
establishes accounting and reporting standards for derivative instruments and
hedging activities. The Company has not used derivative or hedging instruments
since 1996, but may consider hedging some portion of its oil production inYou should read the
future. The Company does not believe, however, that the adoption of SFAS 133
will have a material effect on its results of operations or financial position.
The following discussion of the results of operations for the
three and nine month periodsmonths ended SeptmberSeptember 30, 2001 and 2000 and 1999 andthe financial
condition as atof September 30, 20002001 and December 31, 1999 should be read2000 in conjunction with the
Company'sour
Consolidated Financial Statements and related Notes thereto included in PART I,
Item 1, "Financial Statements".
RESULTS OF OPERATIONSStatements." The Company's results of operations for the three and nine
months ended September 30, 2001 and 2000 are not necessarily indicative of the
operating results for a full year or for future operations.
THREE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000
Our results of operations for the three months ended September 30, 2001
primarily reflected the results for Benton-Vinccler C.A. in Venezuela, which
accounted for substantially all of the Company'sour production and oil sales revenue. As a result of
increases indecreased world crude oil prices, which were
partially offset by lower production from the South Monagas Unit, oil sales in Venezuela were 66% higher17 percent lower
in 20002001 compared to 1999, with a 78% increase in
realized2000. Realized fees per barrel decreased 17 percent (from
$8.25$15.81 in 19992000 to $14.71$13.15 in 2000)2001) and a 7%
decrease in oil sales quantities (from 7.4were substantially
unchanged (2.4 million barrels of oil in 1999 to 6.9
million barrels of oil in 2000)2000 and 2001). OperatingOur operating expenses
from the South Monagas Unit
increased 18%unit decreased 22 percent primarily due to increased chemical treatment, electricitydecreased
workover costs.
We had revenues of $31.4 million for the three months ended September 30, 2001.
The expenses we incurred during the period consisted of:
- operating expenses of $9.7 million;
- depletion, depreciation and gas
compression station maintenanceamortization expense of $6.0 million;
- general and operation costs which were partially offset
by reduced salariesadministrative expense of $5.5 million;
- taxes other than on income of $1.2 million;
- interest expense of $6.1 million;
24
- income tax expense of $3.5 million; and
material costs.
The following table presents selected expense- minority interest of $1.5 million.
Other items from the Company's
consolidatedof income statement items as a percentageconsisted of:
- investment income and other of oil$0.7 million;
- net gain on exchange rates of $0.3 million; and
gas sales:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------------------- ---------------------------------
2000 1999 2000 1999
-------------- ------------- ------------ --------------
Operating Expenses 34% 41% 34% 49%
Depletion, Depreciation and Amortization 11 15 11 21
General and Administrative 10 18 12 28
Taxes Other Than on Income 4 4 3 4
Interest 19 29 22 36
THREE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999
The Company- equity in net earnings of affiliated companies of $2.9 million.
Our net income was $1.7 million or $0.05 per share (diluted).
By comparison, we had revenues of $38.0 million for the three months ended
September 30, 2000. ExpensesThe expenses we incurred during the period consisted ofof:
- operating expenses of $13.0 million,million;
- depletion, depreciation and amortization expense of $4.1 million,million;
- general and administrative expense of $3.8 million,million;
- taxes other than on income of $1.4 million,million;
- interest expense of $7.3 million,million;
- income tax expense of $5.0 millionmillion; and
- minority interest of $2.0 million.
Other items of income consisted ofof:
- investment income and other of $2.2 million,million;
- net gain on exchange rates of $0.1 million;
- equity in net earnings of affiliated companies of $2.2 million,million; and
- extraordinary gain on the repurchase of long-term notes of $3.1
million.
NetOur net income was $9.0 million or $0.29 per share (diluted).
By comparison, the Company hadOur revenues of $24.6 million for the three months
ended September 30, 1999. Expenses incurred during the period consisted of
operating expenses of $10.2 million, depletion, depreciation and amortization
expense of $3.8 million, write-downs of oil and gas properties and impairments
of $13.0 million, general and administrative expense of $4.4 million, taxes
other than on income of $1.1 million, interest expense of $7.2 million, income
tax expense of $0.9 million and minority interest of $0.2 million. Other items
of income consisted of investment income and other of $2.3 million and equity in
net losses of affiliated companies of $0.1 million. Net loss was $14.1decreased $6.6 million, or $0.48 per share (diluted).
Revenues increased $13.4 million, or 54%,17 percent, during the three months
ended September 30, 20002001 compared to the corresponding period of 1999with 2000. This was due to increaseddecreased oil sales
revenue in Venezuela as a result of increases indecreased world crude oil prices and slightly higherprices. Our sales quantities. Sales
quantities for the three months ended September 30, 20002001 from Venezuela were 2.4
million barrels (25,900 barrels of oil per day) compared to 2.3with 2.4 million
barrels (26,000 barrels of oil per day) for the three months ended September 30,
1999. The
increase in sales quantities of 93,227 barrels, or 4%, was due primarily to the
Venezuelan development drilling program.2000. Prices for crude oil averaged $15.81$13.15 per barrel (pursuant to terms of an
operating service agreement) from Venezuela compared to $10.70 per barrel for the corresponding period of 1999.
Operating expenses increased $2.8 million, or 27%, during the three months ended
September 30, 20002001 compared towith $15.81 per barrel during the three months ended
September 30, 19992000.
Our operating expenses decreased $3.3 million, or 25 percent, during the three
months ended September 30, 2001 compared with the three months ended September
30, 2000, primarily due to increaseddecreased workover costs, chemical treatment, electricity and
gas compression station maintenance and operation which were partially offset by
increased transportation costs. Operating expenses at the South Monagas Unit
during the three months ended September 30, 2001 compared with the same period
of 2000 were $4.00 per barrel and $5.38 per barrel, respectively. We anticipate
that operating expenses at the South Monagas Unit will average between $4.00 and
$4.25 per barrel in 2001 and between $3.00 and $3.50 per barrel in 2002.
Depletion, depreciation and amortization increased $1.9 million, or 46 percent,
during the three months ended September 30, 2001 compared with 2000 primarily
due to decreased salariesproved reserves and benefitsincreased future development costs at the
South Monagas Unit, the termination of our exploration obligation on the Delta
Centro Block in Venezuela.
Depletion, depreciationexchange for our standby letter of credit of $7.7 million in
January 2001, and amortization increased $0.3 million, or 8%, during
the three months
23
23
ended September 30, 2000 comparedestimated costs to terminate the corresponding periodbuilding lease of 1999 primarily
due to increased oil sales quantities.the
former Carpinteria, California headquarters office of $0.5 million. Depletion
expense per barrel of oil
equivalent produced from Venezuela during the three months ended
September 30, 20002001 was $2.12 compared with $1.49 compared to $1.47 during the corresponding period of the previous
year. The Company recognized write-downs of $13.0 million at September 30, 1999
of capitalized costs associated with certain exploration activities.2000. General and
administrative expenses decreased $0.6increased $1.7 million, or 14%45 percent, during the three
months ended September 30, 20002001 compared to the corresponding period of 1999with 2000. This was primarily due to
consent fee payments and legal fees totaling $1.2 million associated with the
Company's reduction in force inamendment of indenture covenants of our senior unsecured notes and the fourth quarterestimated
costs to terminate the building lease of 1999 and other
cost cutting measures.the former Carpinteria, California
headquarters office of $0.8 million. Taxes other than on income increased $0.3decreased $0.2
million, or 27%,14 percent, during the three months ended September 30, 20002001
compared towith the corresponding period of 1999three months ended September 30, 2000 primarily due to increased Venezuelan municipal
taxes, which are a function ofreduced
oil revenues.sales resulting from lower world crude oil prices.
25
Investment income and other decreased $0.1$1.5 million, or 4%68 percent, during the
three months ended September 30, 2001 compared with 2000, comparedprimarily due to the three months ended September 30, 1999.lower
average restricted cash and marketable securities balances. Interest expense
increased $0.1decreased $1.2 million, or 1%16 percent, during the three months ended September
30, 20002001 compared with 2000. This was primarily due to the reduction of average
debt balances, partially offset by a reduction of capitalized interest expense.
Net gain on exchange rates increased $0.2 million for the three months ended
September 30, 1999
primarily2001 compared with 2000 due to changes in the reductionvalue of capitalized interest expense, partially offset
by lower debt balances. The Companythe
Bolivar. We realized income before income taxes and minority interest of $10.7$3.9
million during the three months ended September 30, 20002001 compared to a losswith income of
$12.9$10.7 million in the corresponding period of 1999,
which resulted2000, resulting in increaseddecreased income tax expense of $4.1$1.5
million. The effective tax rate of 47%90 percent varies from the U.S. statutory
rate of 35%35 percent primarily because income taxes are paid on profitable
operations in foreign jurisdictions and no benefit is provided for net operating
losses generated in the U.S. The income attributable to the minority interest
increased $1.8decreased $0.5 million for the three months ended September 30, 20002001 compared
to the three months ended September 30, 1999with 2000, primarily due to the increaseddecreased profitability of Benton-Vinccler and income of
$0.8 million attributable to the minority shareholders of Benton-Vinccler that
was included in the consolidated net loss of the Company during the third
quarter of 1999 because the minority shareholders' losses exceeded their
interest in equity capital.Benton-Vinccler.
Equity in net earnings of affiliated companies increased $2.3$0.7 million, or 32
percent, during the three months ended September 30, 20002001 compared with 2000.
This was due to increased income from Geoilbent and Arctic Gas. Our share of
earnings from Geoilbent was $2.5 million for the three months ended SeptemberJune 30,
19992001 compared with earnings of $2.3 million for 2000. The increase of $0.2
million, or 8 percent, was primarily due to an increase in the Company's share of income
from Geoilbent. During the same period the Company's share of revenues from
Geoilbent were $7.1 million compared to revenues of $2.4 million for the three
month period ended June 30, 1999. The increase of $4.7 million, or 196%, was due
to significantly higherincreased sales quantities and world
crude oil prices partially offset by increased depletion and higher sales quantities.taxes other than on
income. Prices for Geoilbent's crude oil averaged $17.19$19.01 per barrel during the
three months ended June 30, 20002001 compared to $6.63with $17.19 per barrel for the three
months ended June 30, 1999. The Company's2000. Our share of Geoilbent oil sales quantities
increased by 54,84422,335 barrels, or 15%,5 percent, from 355,532 barrels sold during the three months ended June
30, 1999 to 410,376 barrels sold during the
three months ended June 30, 2000 to 432,711 barrels sold during the three months
ended June 30, 2001. Our share of earnings from Arctic Gas was $0.3 million for
the three months ended June 30, 2001 compared with a loss of $0.1 million for
2000. The increase of $0.4 million was primarily due to increased oil sales
quantities.
NINE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000
AND 1999We had revenues of $98.6 million for the nine months ended September 30, 2001.
The Companyexpenses we incurred during the period consisted of:
- operating expenses of $32.2 million;
- depletion, depreciation and amortization expense of $18.7 million;
- write-downs of oil and gas properties and impairments of $0.4 million;
- general and administrative expense of $15.9 million;
- taxes other than on income of $4.4 million;
- interest expense of $18.5 million;
- income tax expense of $10.6 million; and
- minority interest of $4.4 million.
Other items of income consisted of:
- investment income and other of $2.4 million;
- net gain on exchange rates of $0.5 million; and
- equity in net earnings of affiliated companies of $6.3 million.
Our net income was $2.9 million or $0.08 per share (diluted).
By comparison, we had revenues of $101.5 million for the nine months ended
September 30, 2000. ExpensesThe expenses we incurred during the period consisted ofof:
- operating expenses of $34.8 million,million;
- depletion, depreciation and amortization expense of $11.7 million,million;
- write-downs of oil and gas properties and impairments of $1.1 million,million;
- general and administrative expense of $12.3 million,million;
- taxes other than on income of $3.5 million,million;
- interest expense of $22.2 million,million;
- income tax expense of $13.3 millionmillion; and
- minority interest of $5.0 million.
26
Other items of income consisted ofof:
- investment income and other of $6.6 million,million;
- net gain on exchange rates of $0.2 million,million;
- equity in net earnings of affiliated companies of $4.1 million,million; and
- extraordinary gain on the repurchase of long-term notes of $3.1
million.
NetOur net income was $11.7 million or $0.39 per share (diluted).
By comparison, the Company hadOur revenues of $61.0 million for the nine months
ended September 30, 1999. Expenses incurred during the period consisted of
operating expenses of $29.6 million, depletion, depreciation and amortization
expense of $12.8 million, write-downs of oil and gas properties and impairments
of $14.3 million, general and administrative expense of $16.9 million, taxes
other than on income of $2.5 million, interest expense of $22.0 million, income
tax expense of $2.1 million and minority interest of $0.5 million. Other items
of income consisted of investment income and other of $7.0 million, net gain on
exchange rates of $0.9 million and equity in net earnings of affiliated
companies of $1.4 million. Net loss was $30.3decreased $2.9 million, or $1.03 per share
(diluted).
Revenues increased $40.5 million, or 66%,3 percent, during the nine months ended
September 30, 20002001 compared to the corresponding period of 1999with 2000. This was due to increaseddecreased oil sales
revenue in Venezuela as a result of increasesdecreases in world crude oil prices
partiallysubstantially offset by lowerincreased sales quantities. SalesOur sales quantities for the
nine months ended September 30, 20002001 from Venezuela were 7.4 million barrels
(27,000 barrels of oil per day) compared with 6.9 million barrels compared to 7.4
million(25,100
barrels of oil per day) for the nine months ended September 30, 1999.2000. The
decreaseincrease in sales quantities of 518,617481,055 barrels, or 7%7 percent, was primarily due primarily
to the curtailmentinfill drilling program that began in 1999 of the Venezuelan development drilling program.January 2000 and ended in December
2000. Prices for crude oil averaged $14.71$13.39 per barrel (pursuant to terms of an
operating service agreement) from Venezuela compared to $8.25 per barrel for the corresponding period of
1999.
Operating expenses increased $5.2 million, or 18%, during the nine months ended
September 30, 20002001 compared to the nine months ended September 30, 1999
primarily due to increased chemical treatment, electricity and gas compression
station maintenance and operation costs which were partially offset by reduced
salaries and material costs at the South Monagas Unit in Venezuela. Depletion,
depreciation and amortization decreased $1.1 million, or 9%,with $14.71 per barrel during the nine months ended
September 30, 20002000.
Our operating expenses decreased $2.6 million, or 7 percent, during the nine
months ended September 30, 2001 compared towith the corresponding period of 1999nine months ended September
30, 2000. This was primarily due to reduceddecreased workover costs substantially
offset by a 7 percent increase in oil sales quantities.production at the South Monagas Unit in
Venezuela, increased electricity and transportation costs. Operating expenses at
the South Monagas Unit during the nine months ended September 30, 2001 compared
with the same period of 2000 were $4.30 per barrel and $4.98 per barrel,
respectively. Depletion, depreciation and amortization increased $7.0 million,
or 60 percent, during the nine months ended September 30, 2001 compared with
2000 primarily due to increased oil production, decreased proved reserves and
increased future development costs at the South Monagas Unit, the termination of
our exploration obligation on the Delta Centro Block in exchange for our standby
letter of credit of $7.7 million in January 2001, the estimated costs to
terminate the building lease of the former Carpinteria, California headquarters
office of $1.4 million, and a reduction in the carrying value of fixed assets
that will not be transferred to Houston of $0.4 million. Depletion expense per
24
24
barrel of oil equivalent produced from Venezuela during the nine months ended September 30,
20002001 was $2.12 compared with $1.48 compared to $1.55 during the corresponding period
of the previous year. The Company2000. We recognized write-downs of
$0.4 million and $1.1 million at September 30, 2001 and $14.32000, respectively, of
capitalized costs associated with exploration prospects. The write-downs were
primarily related to costs associated with the California Leases in 2001 and the
Jordan PSA in 2000. General and administrative expenses increased $3.6 million,
or 29 percent, during the nine months ended September 30, 20002001 compared with
2000. This was primarily due to severance and 1999,
respectively,termination benefits for 27
employees of capitalized costs$0.9 million associated with certain exploration
activities. Generalthe reduction in force and administrative expenses decreased $4.6corporate
restructuring plan adopted in June 2001, legal and professional fees of $1.0
million associated with the offer to restructure our senior notes due May 1,
2003, consent fee payments and legal fees totaling $1.2 million associated with
the amendment of indenture covenants of our senior unsecured notes, the
estimated costs to terminate the building lease of the former Carpinteria,
California headquarters office of $0.8 million, and severance payments
aggregating $0.9 million to two executive officers who resigned during the first
quarter of 2001. These increases were partially offset by the reduction in our
headquarters staff and the relocation of our headquarters to Houston, Texas.
Taxes other than on income increased $0.9 million, or 27%,26 percent, during the
nine months ended September 30, 20002001 compared towith the corresponding
period of 1999nine months ended
September 30, 2000 primarily due to a one-time municipal tax adjustment due to a
change in tax rates at the Company's reductionSouth Monagas Unit in force in the fourth
quarter of 1999Venezuela, substantially offset
by decreased oil sales revenue.
Investment income and other cost cutting measures. Taxes other than on income
increased $1.0decreased $4.2 million, or 40%,64 percent, during the
nine months ended September 30, 20002001 compared to the corresponding period of 1999with 2000, primarily due to increased
Venezuelan municipal taxes, which are a function of oil revenues.
Investment incomelower
average restricted cash and othermarketable securities balances. Interest expense
decreased $0.4$3.7 million, or 6%,17 percent, during the nine months ended September
30, 20002001 compared to the nine months ended September 30,
1999 due to lower average cash and marketable securities balances. Interest
expense increased $0.2 million, or 1%, during the nine months ended September
30, 2000 compared to the nine months ended September 30, 1999with 2000. This was primarily due to the reduction of capitalized interest expenseaverage
debt balances, partially offset by thea reduction of debt balances.capitalized interest expense.
Net gain on exchange rates decreased $0.7increased $0.3 million or 78% for the nine months ended
September 30, 20002001 compared to the corresponding period of
1999with 2000 due to changes in the value of the
Bolivar. The CompanyWe realized income before income taxes and minority interestinterests of $22.8$11.5
million during the nine months ended September 30, 20002001 compared to a losswith income of
$29.1$22.8 million in the
corresponding period of 1999, which resulted2000, resulting in increaseddecreased income tax expense of $11.2$2.7
million. The effective tax rate of 58%92 percent varies from the U.S. statutory
rate of 35%35 percent primarily because income taxes are paid on profitable
operations in foreign jurisdictions and no benefit is provided for net operating
losses generated in the U.S. The income attributable to the minority interest
increased $4.5decreased $0.6 million for the nine months ended September 30, 20002001 compared
to the nine months ended
September 30, 1999with 2000, primarily due to the increaseddecreased profitability of Benton-Vinccler. The increase was partially offset by losses attributable to the
minority shareholders of Benton-Vinccler that were included in the consolidated
net loss of the Company during the first half of 1999 because the minority
shareholders' losses exceeded their interest in equity capital.
Equity in net earnings of affiliated companies increased $2.7$2.2 million, or 193%,54
percent, during the nine months ended September 30, 20002001 compared to the nine months
ended September 30, 1999with 2000.
This was primarily due to the increased income from Geoilbent.
The Company'sGeoilbent and decreased losses
from Arctic Gas. Our
27
share of revenuesearnings from Geoilbent were $16.8was $6.8 million for the nine months ended June
30, 20002001 compared to revenueswith earnings of $6.3$4.8 million for the nine
month period ended June 30, 1999.2000. The increase of $10.5$2.0
million, or 167%,42 percent, was due to significantly higher world crude oil prices partially offset by lowerand increased
sales quantities. Prices for Geoilbent's crude oil averaged $15.71$19.06 per barrel
during the nine months ended June 30, 20002001 compared to $5.89with $15.70 per barrel for
the nine months ended June 30, 1999. The Company's2000. Our share of Geoilbent oil sales quantities
decreasedincreased by 4,284209,093 barrels, or 1%,20 percent, from 1,070,799 barrels sold during the nine
months ended June 30, 1999 to 1,066,515 barrels sold during
the nine months ended June 30, 2000 to 1,275,608 barrels sold during the nine
months ended June 30, 2001. Our share of losses from Arctic Gas was $0.5 million
for the nine months ended June 30, 2001 compared with losses of $0.7 million for
2000. The decrease of $0.2 million, or 29 percent, was primarily due to
initiation of oil sales in June 2000.
28
CAPITAL RESOURCES AND LIQUIDITY
The oil and natural gas industry is a highly capital intensive and cyclical
business with unique operating and financial risks. We require capital
principally to service our debt and to fund the following costs:
- drilling and completion costs of wells and the cost of production and
transportation facilities;
- geological, geophysical and seismic costs; and
- acquisition of interests in oil and gas properties.
The amount of available capital will affect the scope of our operations and the
rate of our growth. Our future rate of growth also depends substantially upon
the prevailing prices of oil. Prices also affect the amount of cash flow
available for capital expenditures and our ability to service our debt.
Additionally, our ability to pay interest on our debt and general corporate
overhead is dependent upon the ability of Benton-Vinccler to make loan
repayments, dividend and other cash payments to us.
Debt Reduction and Restructuring Program. We currently have significant debt
principal obligations payable in 2003 ($108 million) and 2007 ($105 million). As
described below, we have reduced our obligations due in 2003 by $17 million
since September 10, 2000.
During September 2000, we exchanged 2.7 million shares of our common stock, plus
accrued interest, for $8 million face value of the 11.625 percent senior
unsecured notes, and we purchased $5 million face value of the 11.625 percent
senior unsecured notes for cash of $3.5 million, plus accrued interest.
Additionally, in November 2000, we exchanged 1.5 million shares of our common
stock, plus accrued interest, for an aggregate of $4 million face value of the
11.625 percent senior unsecured notes. We anticipate continuing to exchange our
common stock or cash for such notes at a substantial discount to their face
value, if available on economic terms and subject to certain limitations. Under
the rules of The New York Stock Exchange, our common stockholders would need to
approve the issuance of an aggregate of more than 5.9 million shares of common
stock in exchange for senior notes. The effect of further issuances in excess of
5.9 million shares of common stock in exchange for senior notes will be to
materially dilute the existing stockholders if material portions of the senior
notes are exchanged. The dilutive effect on the common stockholders would depend
upon a number of factors, the primary ones being the number of shares issued,
the price at which the common stock is issued, and the discount on the senior
notes exchanged.
In May 2001, we initiated a process intended to effectively extend the maturity
of the senior notes due May 1, 2003 by exchanging new 13.125 percent senior
notes due December 2007 plus warrants to purchase shares of our common stock for
each of the 2003 Notes. The exchange offer was withdrawn in July 2001 and in
August 2001, we solicited and received the requisite consents from the holders
of both the 2003 Notes and the 2007 Notes to amend certain covenants in the
indentures governing the notes to enable Arctic Gas Company to incur nonrecourse
debt of up to $77 million to fund its oil and gas development program. As an
incentive to consent, we offered to pay each noteholder an amount in cash equal
to $2.50 per $1,000 principal amount of notes held for which executed consents
were received. The total amount of consent fees paid to the consenting
noteholders was $0.3 million.
Working Capital. Our capital resources and liquidity are affected by the timing
of our semiannual interest payments of approximately $11.2 million each May 1
and November 1 and by the quarterly payments from PDVSA at the end of the months
of February, May, August and November pursuant to the terms of the contract
between Benton-Vinccler and PDVSA regarding the South Monagas Unit. As a
consequence of the timing of these interest payment outflows and the PDVSA
payment inflows, our cash balances can increase and decrease dramatically on a
few dates during the year. In each May and November in particular, interest
payments at the beginning of the month and PDVSA payments at the end of the
month create large swings in our cash balances. In October 2000, an uncommitted
short-term working capital facility of 8 billion Bolivars (approximately $11
million) was made available to Benton-Vinccler by a Venezuelan commercial bank.
The credit facility bears interest at fixed rates for 30-day periods, is
guaranteed by us and contains no restrictive or financial ratio covenants. We
borrowed 5.4 billion Bolivars (approximately $7.7 million) in January 2001 under
this facility, which we repaid in February 2001. Again in October 2001, we
borrowed 5 billion Bolivars (approximately $6.7 million) under the facility
which will be repaid in November 2001 after the receipt of the third quarter
payment from PDVSA. We believe that similar arrangements will be available to us
in future quarters. At September 30, 2001, the facility had no outstanding
balance.
We will need additional funds in the future for both the development of our
assets and the service of our debt, including the debt maturing in 2003.
Therefore, we will be required to develop sources of additional capital and/or
reduce or reschedule our cash requirements by various techniques including, but
not limited to, the pursuit of one or more of the following strategic
alternatives:
29
- reducing the total debt outstanding by exchanging debt for equity or
by repaying debt with proceeds from the sale of assets, each on
appropriate terms;
- managing the scope and timing of our capital expenditures,
substantially all of which are within our discretion;
- forming joint ventures or alliances with financial or other industry
partners;
- selling all or a portion of our existing assets, including interests
in our assets;
- issuing debt or equity securities or otherwise raise additional funds;
- merging or combining with another entity or sell the Company; or
- reducing our cost structure.
There can be no assurance that any of the above alternatives, or some
combination thereof, will be available or, if available, will be on terms
acceptable to us.
The net funds raised and/or used in each of the operating, investing and
financing activities are summarized in the following table and discussed in
further detail below:
NINE MONTHS ENDED
SEPTEMBER 30,
----------------------------
2001 2000
------------- -------------
Net cash provided by operating activities $ 34,663 $ 46,575
Net cash used in investing activities (37,701) (43,790)
Net cash provided by (used in) financing activities 6,367 (2,816)
------------- -------------
Net increase (decrease) in cash $ 3,329 $ (31)
============= =============
At September 30, 2001, we had current assets of $60.4 million and current
liabilities of $56.8 million, resulting in working capital of $3.6 million and a
current ratio of 1.06 to 1. This compares with our working capital of $12.3
million and a current ratio of 1.24 to 1 at December 31, 2000. The decrease in
oil salesworking capital of $8.7 million was primarily due to capital expenditures at the
South Monagas Unit, partially offset by long-term debt incurred by
Benton-Vinccler for the construction of a 31-mile pipeline, payment of
semi-annual interest on senior unsecured notes and additional investments in
Arctic Gas Company.
Cash Flow from Operating Activities. During the nine months ended September 30,
2001 and 2000, net cash provided by operating activities was approximately $34.7
million and $46.6 million, respectively. Cash flow from operating activities
decreased by $11.9 million during the nine months ended September 30, 2001
compared with 2000. This was primarily due to reductions in accounts payable and
accrued expenses, increased general and administrative expenses and decreased
investment income which were substantially offset by increased collections of
accrued revenues, reduced interest payments and reduced operating expenses.
Cash Flow from Investing Activities. During the nine months ended September 30,
2001 and 2000, we had drilling and production related capital expenditures of
approximately $34.6 million and $40.1 million, respectively. Of the 2001
expenditures:
- $26.0 million was attributable to the temporary interruptiondevelopment of the South Monagas
Unit in Venezuela;
- $7.7 million was related to costs on the Delta Centro Block in
Venezuela; and
- $0.9 million was attributable to other projects.
In addition, during the nine months ended September 30, 2001, we increased our
investment in Arctic Gas by $15.2 million, consisting of purchases of additional
shares totaling $4.7 million, additional loans of $6.5 million and other costs,
consisting primarily of geological and geophysical costs, of $4.0 million.
As a result of the decline in oil prices, in 1999 we instituted a capital
expenditure program to reduce expenditures to those that we believed were
necessary to maintain current producing properties. In the second half of 1999,
oil prices recovered substantially. In December 1999, we entered into
incentive-based development alliance agreements with Schlumberger and Helmerich
& Payne as part of our plans to resume development of the South Monagas Unit in
Venezuela. During 2000, we drilled 26 new oil wells and re-entered 2 oil wells
in the Uracoa Field under the alliance agreements utilizing Schlumberger's
technical and engineering resources.
As part of our strategic shift in focus on the value of the barrels produced, in
January 2001 we suspended the development drilling program in Venezuela until
the second half of 2001. During this period, with the assistance of alliance
partner Schlumberger, all aspects of operations are being thoroughly reviewed to
integrate field performance to date with revised computer simulation modeling
and improved well completion technology. We expect the result will be a
streamlined and more effective infill drilling and well workover program that is
part of an overall reservoir management strategy to drain the remaining
estimated 123 million barrels (98 million barrels net to Benton) of proved
reserves of oil in the fields. Our goal will be an accelerated development
30
program with lower cost production rising to an expected level of up to between
31,000 to 33,000 barrels of oil equivalent per day in less than two years.
In August 2001, drilling re-commenced in the Uracoa Field under the alliance
agreement with Schlumberger. We anticipate drilling a total of eight new wells
in Uracoa and drill six to ten wells in the Tucupita Field commencing in late
2001 or early 2002. In August 2001, Benton-Vinccler signed an agreement to amend
the alliance with Schlumberger. The amended long-term incentive-based alliance
continues to provide incentives intended to improve initial production rates of
new wells and to increase the average life of the downhole pumps at South
Monagas. In addition, Schlumberger has agreed to provide drilling and completion
services for new wells utilizing fixed lump-sum pricing. We chose not to renew
the alliance with Helmerich & Payne and have entered into a standard drilling
contract with Flint. In September 2001, we completed the reservoir simulation
study of the Uracoa Field and expect to complete a revised field development
plan, incorporating the results of this study, in the early part of 2002.
Results of the first three wells drilled under the renewed development drilling
program have been successful with initial production rates approximately double
the initial production rates of the wells drilled in 2000.
We expect capital expenditures of approximately $20 to 25 million during the
next 12 months, substantially all of which will be at the South Monagas Unit.
Additionally, we are negotiating a loan for Arctic Gas that is expected to
minimize future investments in Arctic Gas. In addition, we anticipate providing
or arranging loans of up to $100 million over time to Arctic Gas pursuant to an
equity acquisition agreement signed in April 1999; to date, we have loaned
Arctic Gas $28.5 million under this agreement. We continue to evaluate funding
alternatives for the loans to Arctic Gas. In August 2001, we solicited and
received the requisite consents from the holders of both the 2003 Notes and the
2007 Notes to amend certain covenants in the indentures governing the notes to
enable Arctic Gas Company to incur nonrecourse debt of up to $77 million to fund
its oil and gas development program. The timing and size of the investments for
the South Monagas Unit and Arctic Gas are substantially at our discretion. We
anticipate that Geoilbent will continue to fund its expenditures through its own
cash flow and credit facilities. Our remaining capital commitments worldwide are
relatively minimal and are substantially at our discretion. We will also be
required to make interest payments of approximately $22 million related to our
outstanding senior notes during the next 12 months.
We continue to assess production levels and commodity prices in conjunction with
our capital resources and liquidity requirements. The results from the new wells
drilled in the Uracoa Field in Venezuela indicate that the reservoir formation
quality is as expected, but may be sensitive to drilling and completion
practices. Additionally, a number of previously producing wells went off
production during 2000, requiring maintenance operations. We are working with
our alliance partner on techniques to optimize the production from new wells and
believe that we can achieve improvements in production performance from the
Uracoa Field. Results of the first four wells drilled under the renewed 2001
development drilling program illustrate significant progress in optimizing
production from new wells with initial production rates approximately double the
initial production rates of the wells drilled in 2000.
Current production from Arctic Gas' Samburg license block is approximately 2,700
barrels of oil per day and current production from Geoilbent's North Gubkinskoye
and Prisklonovoye Fields is approximately 14,000 barrels of oil per day.
Additionally, in July 2001, Geoilbent commenced oil production from the first
development well in the South Tarasovskoye Field. The well, drilled to a total
depth of 9,535 feet, encountered a 365 foot gross oil column in multiple
productive intervals, and established the first production from the Geoilbent
100 percent owned Urabor Yakhinsky Block in Western Siberia, Russia. During the
third quarter, Geoilbent drilled four additional wells in the South Tarasovskoye
Field, which are currently producing approximately 6,000 barrels per day. The
initial discovery and production from this field came from the adjacent
Purneftegaz acreage in May of this year. Evaluation of the exploratory appraisal
well to test the extension of the South Tarasovskoye Field is continuing. At
least one more exploration well and follow up exploitation drilling will be
required to determine the full significance of the South Tarasovskoye Field. We
believe this field could add significant, high quality reserves and cash flow to
our Russian assets.
We believe the seven new wells drilled in the South Tarasovskoye Field since
July 2001 significantly increase the value of our Russian properties and we are
reviewing alternatives to maximize their value. These alternatives include
accelerating the Russian development programs and the potential sale of all or
part of the Russian assets.
Cash Flow from Financing Activities. In May 1996, we issued $125 million in
11.625 percent senior unsecured notes due May 1, 2003, of which we repurchased
$17 million at their discounted value in September and November 2000. The notes
were repurchased with the issuance of 4.2 million common shares and cash of $3.5
million plus accrued interest. In November 1997, we issued $115 million in 9.375
percent senior unsecured notes due November 1, 2007, of which we subsequently
repurchased $10 million at their par value for cash. Interest on all of the
notes is due May 1 and November 1 of each year. The indenture agreements provide
for certain limitations on liens, additional indebtedness, certain investment
and capital expenditures, dividends, mergers and sales of assets. At September
30, 2001, we were in compliance with all covenants of the indentures.
31
In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan
commercial bank, in the form of two loans, for construction of a 31-mile oil
pipeline that will connect the Tucupita Field production facility with the
Uracoa central processing unit. The first loan, in the amount of $6 million,
bears interest payable monthly based on 90-day LIBOR plus 5 percent with
principal payable quarterly for five years. The second loan, in the amount of
4.4 billion Venezuelan Bolivars (approximately $6.3 million), bears interest
payable monthly based on a mutually agreed interest rate determined quarterly or
a 6-bank average published by the central bank of Venezuela. The interest rate
for the quarter ending September 2001 was 21 percent with an effective interest
rate of 7.8 percent taking into account exchange rate gains resulting from
devaluation of the Bolivar during the quarter.
We recently received a letter from the New York Stock Exchange ("NYSE")
notifying us that we have fallen below the continued listing standards of the
NYSE. These standards include a total market capitalization of at least $50
million over a 30-day trading period and stockholders' equity of at least $50
million. According to the NYSE's notice, our total market capitalization over
the 30 trading days ended October 17, 2001, was $48.2 million, and our
stockholders' equity as of June 30, 2001, was $14.3 million ($16 million at
September 30, 2001). In accordance with the NYSE's rules, we intend to submit a
plan to the NYSE by mid-December detailing how we expect to reestablish
compliance with the listing criteria within the next 18 months. The NYSE is
expected to respond to the plan within 45 days after it is submitted. Because of
our ongoing efforts to implement our strategic plan for improvements and to
evaluate alternatives to restore our financial flexibility, we believe that we
will be able to meet the NYSE's continued listing standards in the future. These
alternatives include continued cost reductions, production enhancements, selling
all or part of our assets in Venezuela and/or Russia, restructuring the debt or
some combination of these alternatives. We may also recommend selling the
Company. However, we cannot give any assurance that any of these steps can be
successfully completed or that we ultimately will determine that any of these
steps should be taken. Failure to meet the NYSE criteria may result in the
delisting of our common stock on the NYSE. As a result, an investor may find it
more difficult to dispose or obtain quotations or market value of our common
stock, which may adversely affect the marketability of our common stock.
However, given our strategic plan referenced above, we are optimistic that we
will be able to meet the NYSE requirements in the future and consequently, do
not expect our stock to be delisted.
CONCLUSION
While no assurance can be given, we currently believe that we have sufficient
flexibility with our discretionary capital expenditures and investments in and
advances to affiliates that our capital resources and liquidity will be adequate
to fund our semiannual interest payment obligations for the next 12 months. This
expectation is based upon our current estimate of projected price levels,
production and the availability of short-term working capital facilities of up
to $11 million during the time periods between the submission of quarterly
invoices to PDVSA by Benton-Vinccler and the subsequent payments of these
invoices by PDVSA. Actual results could be materially affected if there are
significant additional decreases in crude oil prices or decreases in production
levels related to the South Monagas Unit. Future cash flows are subject to a
number of variables including, but not limited to, the level of production and
prices, as well as various economic conditions that have historically affected
the oil and natural gas business. Prices for oil are subject to fluctuations in
early 2000 resultingresponse to changes in supply, market uncertainty and a variety of factors
beyond our control. We estimate that a change in the price of oil of $1.00 per
barrel would affect cash flow from an accident
duringoperations by approximately $0.8 million
based on our third quarter production rates and cost structure.
However, our ability to retire our long-term debt obligations due in the periodyear
2003 is highly dependent upon our success in pursuing some or all of the
strategic alternatives described above. There can be no assurance that affected certain production facilities.such
efforts will produce enough cash for retirement of these obligations or that
these obligations could be refinanced or restructured.
DOMESTIC OPERATIONS
In April and May 2000, the Companywe entered into a retainer agreement, and in May 2000 an
exploration agreement,agreements with Coastline Energy
Corporation ("Coastline") for the purpose of acquiring, exploring and developing
oil and natural gas prospects both onshore and in the state waters of the Gulf
Coast states of Texas, Louisiana and Mississippi. Under the agreements,
Coastline will evaluateevaluated prospects in the Gulf Coast area for possible acquisition
and development by the Company.us. During the 18-month term of the exploration agreement, the Company will reimbursewe
reimbursed Coastline for certain of its overhead and prospect evaluation costs.
Under the agreements, for prospects evaluated by Coastline and acquired by the Company,that we acquire,
Coastline will receive compensation based on (a) oil and natural gas production
acquired or developed and (b) on the profits, if any, resulting from the sale of
such prospects. In April 2000, pursuant to the agreements, the Companywe acquired an
approximate 25%25 percent working interest in the East Lawson Field in Acadia
Parish, Louisiana. The acquisition included a 15%15 percent working interest in two
producing oil and natural gas wells. During the year ended December 31, 2000,
our share of the East Lawson Field production was 6,884 barrels of oil and
43,352 Mcf of natural gas, resulting in income from United States oil and
natural gas operations of $0.3 million. In December 2000, we sold our interest
in the East Lawson Field for $0.8 million in cash. Additionally, we acquired a
100 percent
32
working interest in the Lakeside Exploration Prospect in Cameron Parish,
Louisiana. We farmed out 90 percent of the working interest in the prospect for
$0.5 million cash and a 16.2 percent carried interest in the first well. We
anticipate that drilling of the well will commence before December 2001. The
agreement with Coastline was terminated on August 31, 2001. However, certain
ongoing operations related to the Lakeside Exploration Prospect may be conducted
by Coastline on a consulting basis.
In March 1997, the Companywe acquired a 40%40 percent participation interest in three
California State offshore oil and natural gas leases ("California Leases") from
Molino Energy Company, LLC ("Molino Energy"), which held 100%100 percent 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%40 percent participation interest in the California Leases, the Companywe became the
operator of the project and agreed to pay 100%100 percent of the first $3.7 million
and 53%53 percent of the remainder of the costs of the first well drilled on the
block. During 1998, the 2199 #7 exploratory well was drilled to the Gaviota
anticline. Drill stem tests proved to be inconclusive or non-commercial, and the
well was temporarily abandoned for further evaluation. In November 1998, the Companywe
entered into an agreement to acquire Molino Energy's interest in the California
Leases in exchange for the release of itstheir joint interest billing obligations,
but the transaction has not yet been finalized.obligations.
In the fourth quarter of 1999, the Companywe decided to focus itsour capital expenditures on
existing producing properties and fulfilling work commitments associated with
itsour other properties. Because the Company haswe had no firm approved plans to continue drilling
on the California Leases and the 2199 #7 exploratory well did not result in
commercial reserves, the Companywe wrote off all of the capitalized costs associated with
the California Leases of $9.2 million and the joint interest receivable of $3.1
million due from Molino Energy at December 31, 1999. 25
25However, we continue to
evaluate the prospect for potential future drilling activities.
INTERNATIONAL OPERATIONS
On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), signed an operating service agreement to reactivate
and further develop three Venezuelan oil fields with an affiliate of the
national oil company, Petroleos de Venezuela, S.A. ("PDVSA"). The operating
service agreement covers the Uracoa, Bombal and Tucupita Fields that comprise
the South Monagas Unit (the "Unit"). Under the terms of the operating service
agreement, Benton-Vinccler, a corporation owned 80 percent by us and 20 percent
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. The Venezuelan government maintains full ownership
of all hydrocarbons in the fields.
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%.34 percent. However, Benton-Vinccler reported significantly lower
effective tax rates for 1998 due to the effect of the devaluation of the Bolivar
while Benton-Vinccler uses the U.SU.S. dollar as its functional currency. The effective
tax rate for 1999 was lower due to a decrease in the valuation allowance. The
CompanyWe cannot
predict the timing or impact of future devaluations in Venezuela.
A 3-D seismic survey has been conducted over the southwestern portion of, and a
371 kilometer 2-D seismic survey has been acquired for, the Delta Centro Block
in Venezuela. During 1999, the Block's first exploration well, the Jarina 1-X,
penetrated a thick potential reservoir sequence, but encountered no commercial
hydrocarbons. The Company continues to evaluate the remaining leads on the
Block, including their potential reserves and risk factors, although the Block's
future exploration activities and potential commerciality are uncertain.. The
total cost to the Company of acquiring the seismic data and drilling the Jarina
1-X was $15.3 million. The Company's operations related to Delta Centro, if any,
will be subject to oil and gas industry taxation, which currently provides for
royalties of 16.66% and income taxes of 67.7%.
Russian companies are subject to a statutory income tax rate of 30% and are
subject to various other tax burdens and tariffs. Excise, pipeline and other
tariffs and taxes continue to be levied on all oil producers and certain
exporters, including an oil export tariff that increased to 34 Euros per ton
(approximately $3.80 per barrel) on November 1, 2000 from 15 Euros per ton in
1999. The Company is unable to predict the impact of taxes, duties and other
burdens for the future for its Russian operations.
In December 1996, the Companywe acquired Benton Offshore China Company,Crestone Energy Corporation, a privately held
company headquartered in Denver, Colorado.Colorado, subsequently renamed Benton Offshore
China Company'sCompany. Its principal asset is a petroleum contract with CNOOCChina National
Offshore Oil Corporation ("CNOOC") for an area known
as Wan'An Bei, WAB-21.the WAB-21 area. The WAB-21 petroleum
contract covers 6.2 million acres in the South China Sea, with an option for another onean
additional 1.0 million acres under certain circumstances, and lies within an
area thatwhich 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 existedlasted for many years, and
there has been limited exploration and no development activity in the area under
dispute.
It is
uncertainChina's claim of ownership of the area results from China's discovery and use
and historic administration of the area. This claim also includes third party
and official foreign government recognition of China's sovereignty and
jurisdiction over the contract area. Despite this claim, the territorial dispute
may not be resolved in favor of China. We cannot predict how or when, or howif at all,
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
discussionor whether it would result in the Company'sour interest being
reduced. Benton Offshore China Company has submitted plans and budgets to CNOOC
for an initial seismic program to survey the area. However, exploration
activities will be subject to resolution of such territorial dispute. At
September 30, 2000, the Company has2001, we had recorded no proved reserves attributable to this
petroleum contract.
In August 1997, the Company acquired the rights to an Exploration and Production
Sharing Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to
explore, develop and produce the Sirhan Block in southeastern Jordan. The Sirhan
Block consists of approximately 1.2 million acres (4,827 square kilometers) and
is located in the Sirhan Basin adjacent to the Saudi Arabia border. Under the
terms of the PSA, the Company was obligated to spend $5.1 million in the first
exploration phase, which was extended to May 2000, for which it posted a $1
million standby letter of credit collateralized in full by a time deposit of the
Company. During the first quarter of 1998, the Company reentered two wells and
tested two different reservoirs. The WS-9 well tested significant, but
non-commercial amounts of gas; the WS-10 well resulted in no commercial amounts
of hydrocarbons. Therefore, at December 31, 1998, the Company wrote down $3.7
million in capitalized costs incurred to date related to the PSA. During 1999,
the Company incurred an additional $0.3 million in capitalized costs, which were
written off at December 31, 1999. As of the May 17, 2000 expiration date of the
PSA, the Company had elected not to complete the first exploration phase of the
agreement. As a result, during the second quarter of 2000, the Company recorded
a liability to the NRA for the obligation remaining under the PSA resulting in
impairment expense of $1.0 million. The NRA collected on the letter of credit in
August 2000.
In October 1999, the Company entered into an agreement with First Seismic
Corporation ("First Seismic") whereby the Company, upon receiving a release from
Societe des Petroles du Senegal ("Petrosen"), the state oil company of the
Republic of Senegal, of its remaining work commitment, transferred its entire
working interests in the onshore Thies Block in western Senegal and paid $0.7
million to First Seismic in exchange for 135,000 series B preferred shares of
First Seismic. The Company performed a valuation of the securities at the date
of the agreement with First Seismic and concluded that the securities had a de
minimis fair value. Accordingly, the Company has not assigned any cost to the
securities. For the year ended December 31, 1999, the Company recorded a
write-down of $1.6 million comprised of $0.9 million of previously capitalized
costs and of the $0.7 million payment to First Seismic. At September 30, 2000,
the Company evaluated the securities and believes that the fair value of the
securities has not changed since the date of the agreement.
In April 1998, the Companywe signed an agreement to earn a 40%40 percent equity interest in
Arctic Gas.Gas Company. 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 Blockslicense blocks in West Siberia. The two blocks comprise 837,000794,972 acres
within and adjacent to the Urengoy field,Field, Russia's largest producing natural gas
field. Pursuant toUnder the terms of a Cooperation Agreement between the Companyus and Arctic Gas, the Companywe
will earn 26
26
a 40%40 percent equity interest in exchange for providing or arranging the initial
capital needed to achieve the economic self-sufficiency through its own oil and
natural gas production. The Company'sOur capital commitment will be in the form of a credit
facility of up to $100 million for the project, the terms and timing of which
are being negotiated but have yet to be finalized. The CompanyPursuant to the Cooperation
Agreement, we have received voting shares representing a 40%40 percent 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. Due to the
33
significant influence it exerciseswe exercise over the operating and financial policies of
Arctic Gas, the Company accountswe account for itsour 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 Companyus and Arctic Gas, or
to change any terms in any existing agreements, including the conditions upon
which the restrictions on the shares could be removed, betweenremoved.
As of September 30, 2001, we had loaned $28.5 million to Arctic Gas pursuant to
an interim credit facility, with interest at LIBOR plus 3 percent, and had
earned the two suchright to remove restrictions from shares representing an approximate
11 percent equity interest. From December 1998 through September 2001, we
purchased shares representing an additional 28 percent equity interest not
subject to any sale or transfer restrictions. We owned a total of 68 percent of
the outstanding voting shares of Arctic Gas as of September 30, 2001, of which
approximately 39 percent were not subject to any restrictions.
In 1991, we entered into a joint venture agreement with Purneftegazgeologia and
Purneftegaz forming Geoilbent for the Cooperation Agreementpurpose of developing, producing and
marketing crude oil from the Share Disposition Agreement.North Gubkinskoye and Prisklonovoye Fields in the
West Siberia region of Russia located approximately 2,000 miles northeast of
Moscow. Geoilbent was later re-chartered as a limited liability company. We own
34 percent and Purneftegazgeologia and Purneftegaz each own 33 percent of
Geoilbent. The field covers a license block of 167,086 acres, an area
approximately 15 miles long and four miles wide. The field has been delineated
with over 60 exploratory wells, which tested 26 separate reservoirs. Geoilbent
also holds rights to three more license blocks comprising 1,189,757 acres.
Geoilbent commenced initial operations in the North Gubkinskoye and
Prisklonovoye Fields during the third quarter of 1992 with the construction of a
37-mile oil pipeline and installation of temporary production facilities. In
July 2001, Geoilbent commenced production from a development wells in the South
Tarasovskoye Field.
Russian companies are subject to a statutory income tax rate of up to 35 percent
and are subject to various other tax burdens and tariffs. Excise, pipeline and
other tariffs and taxes continue to be levied on all oil producers and certain
exporters, including an oil export tariff that decreased to 22 Euros per ton
(approximately $2.70 per barrel) on March 18, 2001 from 48 Euros per ton in
January 2001. The export tariff increased to 30.5 Euros per ton (approximately
$3.64 per barrel) in July 2001. We are unable to predict the impact of taxes,
duties and other burdens for the future for our Russian operations.
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION
The Company'sOur results of operations and cash flow are affected by changing oil prices.
However, the Company's Venezuelanour South Monagas Unit oil sales are based on a fee adjusted quarterly
by the percentage change of a basket of crude oil prices instead of by absolute
dollar changes, whichchanges. This dampens both any upward and downward effects of changing
prices on the Company'sour Venezuelan oil sales and cash flows. If the price of oil
increases, there could be an increase in theour cost to the Company for drilling and related
services because of increased demand, as well as an increase in oil sales.
Fluctuations in oil and natural gas prices may affect the
Company'sour 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-Vincclerus or the Company.Benton-Vinccler. Currently, there are no exchange controls in
Venezuela or Russia that restrict conversion of local currency into U.S. dollars
for routine business operations, such as the payments of invoices, debt
obligations and dividends.
Within the United States, inflation has had a minimal effect on the Company,us, but it is
potentially an important factor in results of operations in Venezuela and
Russia. With respect to Benton-Vinccler and Geoilbent, a significant majority of
the sources of funds, including the proceeds from oil sales, the Company'sour contributions
and credit financings, are denominated in U.S. dollars, while local transactions
in Russia and Venezuela are conducted in local currency. If the rate of increase
in the value of the dollar compared to the bolivar continues to be less than the
rate of inflation in Venezuela, then inflation could be expected to have an
adverse effect on Benton-Vinccler.
During the nine months ended September 30, 2000, the Company's2001, net foreign exchange gains
attributable to itsour Venezuelan operations were $0.5 million and net foreign
exchange gains attributable to our Russian operations were minimal.$0.2 million.
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 hasour control. We have
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 for us to predict the extent to which the Companywe may be
affected by future changes in exchange rates and exchange controls.
The Company's
34
Our operations are affected by political developments and laws and regulations
in the areas in which it operates.we operate. In particular, oil and natural 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 natural gas wastes, or otherwise relating to the
protection of the environment, may affect the Company'sour operations and results.
CAPITAL RESOURCES AND LIQUIDITY
The oilNEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) No. 141, "Business Combinations," SFAS
142 "Goodwill and gas industryOther Intangible Assets" and SFAS 143 "Accounting for Asset
Retirement Obligations." SFAS 141 eliminates the pooling method of accounting
for a business combination, except for qualifying business combinations that
were initiated prior to July 1, 2001, and requires that all combinations be
accounted for using the purchase method. SFAS 142, which is a highly capital intensive business. The Company
requires capital principallyeffective for fiscal
years beginning after December 15, 2001, addresses accounting for identifiable
intangible assets, eliminates the amortization of goodwill and provides specific
steps for testing the impairment of goodwill. Separable intangible assets that
are not deemed to service its debt and 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.
DEBT REDUCTION PROGRAM. The Company has significant debt principal obligations
payable in 2003 and 2007. During September 2000, the Company exchanged 2.7
million shares of its common stock, plus accrued interest, for $8 million face
value of its 11 5/8% senior notes due in 2003 and purchased $5 million face
value of its 2003 senior notes for cash of $3.5 million plus accrued interest.
Additionally, in November 2000, the Company exchanged 1.4 million shares of its
common stock, plus accrued interest, forhave an aggregate $4 million face value of
its 11 5/8% senior notes due in 2003. The Company anticipates continuing to
exchange its common stock or cash for senior notes at a substantial discount to
their face value if available on economic terms and subject to certain
limitations. Under the rules of the New York Stock Exchange, the common
stockholders would need to approve the issuance of an aggregate of more than
27
27
5.9 million shares of common stock in exchange for senior notes. The effect on
existing shareholders of further issuances in excess of 5.9 million shares of
common stock in exchange for senior notes will be to materially dilute the
existing shareholders if material portions of the senior notes are exchanged.
The dilutive effect on the common stockholders would depend upon a number of
factors, the primary ones being the number of shares issued, the price at which
the common stock is issued, and the discount on the senior notes exchanged.
WORKING CAPITAL. The Company's capital resources and liquidity are affected by
the timing of its semiannual interest payments of approximately $11.4 million
each May 1 and November 1 and by the quarterly payments from PDVSA at the end of
the months of February, May, August and November pursuant to the terms of the
contract between Benton-Vinccler and PDVSA regarding the South Monagas Unit. As
a consequence of the timing of these interest payment outflows and the PDVSA
payment inflows, the Company's cash balances can increase and decrease
dramatically on a few dates during the year. In each May and November in
particular, interest payments at the beginning of the month and PDVSA payments
at the end of the month create large swings in the cash balances. In October
2000, a short-term working capital facility of 8 billion Bolivars (approximately
$11.5 million) was made available to Benton-Vinccler by a Venezuelan commercial
bank. The credit facility bears interest at fixed rates for 30-day periods, is
guaranteed by the Company and contains no restrictive or financial ratio
covenants. The current interest rate on the facility is 18%. The Company
borrowed 5 billion Bolivars (approximately $7.2 million) under this facility,
which it expects to repay in November 2000. The Company believes that similar
arrangements will be available to it in future quarters.
While no assurance can be given, the Company currently believes that its capital
resources and liquidity will be adequate to fund its planned capital
expenditures, investments in and advances to affiliates, and semiannual interest
payment obligations for the next twelve (12) months. This expectation is based
upon anticipated price levels, production and the availability of short-term
working capital facilities of up to $15 million during the time periods between
the submission of quarterly invoices to PDVSA by Benton-Vinccler and the
subsequent payments of these invoices by PDVSA. Actual results could be
materially affected if there is a significant decrease in either price or
production levels related to the South Monagas Unit. Future cash flows are
subject to a number of variables including, but not limited to, the level of
production and prices, as well as various economic conditions that have
historically affected the oil and gas business. 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.
Additional funds will be needed in the future for both the development of the
Company's assets and the service of its debt. Therefore, the Company will be
required to develop sources of additional capital and/or reduce its cash
requirements by various techniques including, but not limited to, the pursuit
of one or more of the following alternatives: significantly reduce or reschedule
its South Monagas Unit, Arctic Gas Company, and other capital expenditures,
substantially all of which are within its discretion; sell property interests;
form joint ventures or alliances with financial or other industry partners;
merge or combine with another entity; or issue debt or equity securities. There
can be no assurance that any of the alternatives will be available on terms
acceptable to the Company.
The net funds raised and/or used in each of the operating, investing and
financing activities are summarized in the following table and discussed in
further detail below:
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2000 1999
--------- --------
Net cash provided by operating activities $ 46,575 $ 1,410
Net cash provided by (used in) investing activities (43,790) 18,245
Net cash used in financing activities (2,816) (15,319)
-------- -------
Net increase (decrease) in cash $ (31) $ 4,336
======= =======
At September 30, 2000, the Company had current assets of $101.8 million and
current liabilities of $92.9 million, resulting in working capital of $8.9
million and current ratio of 1.10:1. This compares to the Company's working
capital of $32.1 million and a current ratio of 2.17:1 at December 31, 1999. The
decrease in working capital of $23.2 million was primarily due to capital
expenditures at the South Monagas Unit in Venezuela and additional investments
in and advances to Arctic Gas Company during the nine months ended September 30,
2000.
CASH FLOW FROM OPERATING ACTIVITIES. During the nine months ended September 30,
2000 and 1999, net cash provided by operating activities was approximately $46.6
million and $1.4 million, respectively. Cash flow from operating activities
increased by $45.2 million during the nine months ended September 30, 2000
compared to the corresponding period of 1999 due primarily to increased
collections of accrued oil revenues and increased accounts payable and accrued
expenses associated with the alliance agreements with Schlumberger and Helmerich
& Payne which were partially offset by increases in operating expenses, income
taxes and taxes other than on income. Collections of accrued oil revenues
increased $38.2 million, and accounts payable and accrued expenses increased
$18.8 million during the nine months ended September 30, 2000 compared to the
corresponding period of 1999.
28
28
CASH FLOW FROM INVESTING ACTIVITIES. During the nine months ended September 30,
2000 and 1999, the Company had drilling and production related capital
expenditures of approximately $40.1 million and $29.4 million, respectively. Of
the 2000 expenditures, $37.9 million was attributable to the development of the
South Monagas Unit in Venezuela, $0.2 million related to costs on the Delta
Centro Block in Venezuela, $1.0 million related to the Sirhan Block in Jordan
and $1.0 million was attributable to other projects. In addition, during the
nine month period ended September 30, 2000, the Company increased its investment
in Arctic Gas by $6.5 million.
In August 1999, Benton-Vinccler sold its power generation facility located in
the Uracoa Field of the South Monagas Unit in Venezuela for $15.1 million.
Concurrently with the sale, Benton-Vinccler entered into a long-term power
purchase agreement with the purchaser of the facility to provide for the
electrical needs of the field throughout the remaining term of the operating
service agreement. Benton-Vinccler used the proceeds from the sale to repay
indebtedness that was collateralized by a time deposit of the Company. Permanent
repayment of a portion of the loan allowed the Company to reduce the cash
collateral for the loan thereby making such cash available for working capital
needs.
As a result of the decline in oil prices, the Company instituted in 1998, and
continued in 1999, a capital expenditure program to reduce expenditures to those
that the Company believed were necessary to maintain current producing
properties. In the second half of 1999, oil prices recovered substantially. In
December 1999, the Company entered into incentive-based development alliance
agreements with Schlumberger and Helmerich & Payne as part of its plans to
resume development of the South Monagas Unit in Venezuela.
The Company expects capital expenditures of approximately $45-50 million during
the next 12 months, including $40-45 million at the South Monagas Unit. The
Company also expects to increase its investment in Arctic Gas by $4-6 million
during the same period. In addition, the Company anticipates providing or
arranging loans of up to $100 million over time to Arctic Gas pursuant to an
equity acquisition agreement signed in April 1998. The Company continues to
evaluate funding alternatives for the loans to Arctic Gas. The timing and size
of the investments for the South Monagas Unit and Arctic Gas are substantially
at the Company's discretion. The Company anticipates that Geoilbentindefinite life will continue to fund its expenditures through its own cash flow and credit
facilities. The Company's remaining capital commitments worldwide are relatively
minimal and are substantially atbe amortized over
their useful lives. SFAS 143, which is effective for fiscal years beginning
after June 15, 2002, requires entities to record the Company's discretion. The Company will also
be required to make interest paymentsfair value of approximately $22 million related to
its outstanding senior notes during the next 12 months.
The Company continues to assess production levels and commodity prices in
conjunction with its capital resources and liquidity requirements. The results
from the new wells drilleda liability
for an asset retirement obligation in the Uracoa Fieldperiod in Venezuela under the alliance
agreements with Schlumberger and Helmerich & Payne indicate that the reservoir
formation qualitywhich it is incurred as expected, but may be sensitive to drilling and
completion practices. Additionally, a
number of previously producing wells went
off production during 2000, requiring maintenance operations. The Company and
its alliance partners are working on techniques to optimize the production from
new wells and believe that improvements in production performance from the
Uracoa Field can be achieved.
CASH FLOW FROM FINANCING ACTIVITIES. In May 1996, the Company issued $125
million in 11.625% senior unsecured notes due May 1, 2003, of which the Company
repurchased $13 million at their discounted value in September 2000. The notes
were repurchased with the issuance of 2.7 million common shares and cash of $3.5
million plus accrued interest. 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 for cash. Interest on
the notes is due May 1st and November 1st of each year. The indenture agreements
provide for certain limitations on liens, additional indebtedness, certain
investment and capital expenditures, dividends, mergers and sales of assets. At
September 30, 2000, the Company was in compliance with all covenantscapitalized cost of the indentures.
COST REDUCTIONSlong-lived asset and to depreciate it over its useful
life. We are currently in the process of evaluating the impact that SFAS 142 and
SFAS 143 will have on our financial position and results of operations.
In an effortOctober 2001, the FASB issued SFAS 144, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to reduce generalBe Disposed Of", which addresses
financial accounting and administrative expenses,reporting for the Company reduced
its administrativeimpairment or disposal of long-lived
assets. SFAS 144 supersedes SFAS 121 and technical staffthe accounting and reporting provisions
of APB Opinion No. 30. SFAS 144 is effective for fiscal years beginning after
December 15, 2001. We are currently in Carpinteria by 10 persons in October
1999. In connection with the reduction in staff,process of evaluating the Company recorded
termination benefits expenses in October 1999impact that
SFAS 144 will have on our financial position and results of $0.8 million. All amounts were
paid as of September 30, 2000.
29
29operations.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company isWe are exposed to market risk from adverse changes in oil and natural gas
prices, interest rates and foreign exchange, as discussed below.
OIL AND NATURAL GAS PRICES
As an independent oil and natural gas producer, the Company'sour revenue, other income and
equity earnings and profitability, reserve values, access to capital and future
rate of growth are substantially dependent upon the prevailing prices of crude
oil and condensate. The Company currently neither produces nor records reserves
related to natural gas. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond the control of the Company.our control. Historically, prices received
for oil and natural gas production have been volatile and unpredictable, and
such volatility is expected to continue. This volatility is demonstrated by the
average realizations in Venezuela, which declined from $10.01 per barrel in 1997
to $6.75 per barrel in 1998 and increased to $14.71$14.94 per barrel in 2000. During
the first nine months ended September 30, 2001, the average realization in Venezuela
was $13.39 per barrel. Based on our budgeted production and costs, we will
require an average realization in Venezuela of 2000.approximately $12.50 per barrel
in 2001 in order to break-even on income from consolidated companies before our
equity in earnings from affiliated companies. From time to time, the Company haswe have
utilized hedging transactions with respect to a portion of itsour oil and natural
gas production to achieve a more predictable cash flow, as well as to reduce itsour
exposure to price fluctuations, but the
Company haswe have utilized no such transactions since
1996. While hedging limits the downside risk of adverse price movements, it may
also limit future revenues from favorable price movements. Because gains or
losses associated with hedging transactions are included in oil sales when the
hedged production is delivered, such gains and losses are generally offset by
similar changes in the realized prices of the commodities. The CompanyWe did not enter into
any commodity hedging agreements during the nine months ended September 30, 2001
or 2000.
INTEREST RATES
Total long-term debt at September 30, 2000,2001 consisted of $217$213 million of
fixed-rate senior unsecured notes maturing in 2003 ($112108 million) and 2007 ($105
million). Another $34.6 and $11.1 million of debt is attributable to a floating-rate back-to-back loan facility wherein Benton-Vinccler pays floating-rate interest
to a bank, which then pays to the Company interest on cash collateral deposited
by the Company to support the loans, such interest to the Company being equal to
the floating rate payment less approximately 0.375% thereby mitigating the
floating-rate interest rate risk of such debt.notes due in 2006. A hypothetical 10%10
percent adverse change in the floating rate would not have had a material affect
on the Company'sour results of operations for the nine months ended September 30, 2000.2001.
35
FOREIGN EXCHANGE
The Company'sOur operations are located primarily outside of the United States. In
particular, the Company'sour current oil producing operations are located in Venezuela and
Russia, countries which have had recent histories of significant inflation and
devaluation. For the Venezuelan operations, oil sales are received under a
contract in effect through 2012 in USU.S. dollars; expenditures are both in USU.S.
dollars and local currency. For the Russian operations, a majority of the oil
sales are received in USU.S. dollars; expenditures are both in USU.S. dollars and
local currency, although a larger percentage of the expenditures wereare in local
currency. The Company hasWe have utilized no currency hedging programs to mitigate any risks
associated with operations in these countries, and therefore the Company'sour financial
results are subject to favorable or unfavorable fluctuations in exchange rates
and inflation in these countries.
30
3036
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.On February 17, 1998, the WRT Creditors Liquidation Trust ("WRT Trust")
filed suit in the United States Bankruptcy Court, Western District of
Louisiana against us and Benton Oil and Gas Company of Louisiana,
a.k.a. Ventures Oil & Gas of Louisiana ("BOGLA"), seeking a
determination that the sale by BOGLA to Tesla Resources Corporation
("Tesla"), a wholly owned subsidiary of WRT Energy Corporation, of
certain West Cote Blanche Bay properties for $15.1 million, constituted
a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550 (the
"Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties and that it
paid a price in excess of the fair value of the property. A trial
commenced on May 1, 2000 that concluded at the end of August 2000, and
post trial briefs were filed. In August 2001, a favorable decision was
rendered in BOGLA's favor denying any and all relief to the WRT Trust.
The WRT Trust has stated that it would appeal the decision prior to the
end of 2001; however, we believe that any such appeal would result in
an outcome consistent with the court's prior decision.
ITEM 2. CHANGES IN SECURITIES
During the three months ended September 30, 2000, the Company
exchanged 2,710,590 shares of common stock and paid cash of
$3,537,500, plus accrued interest, for $13,000,000 face value of its
11.625% senior unsecured notes in private transactions with holders
of the notes. The exchanges were exempt from registration under
Section 3(a)(9) of the Securities Act of 1933 inasmuch as the Company
exchanged securities exclusively with existing noteholders and no
commission or other remuneration was paid with respect to the
exchanges.None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At theour Annual Meeting of the Stockholders of the Company held on July 21, 2000,30, 2001, the
following items were voted on by the Stockholders:Stockholders in addition to the
election of directors:
1. Election of Directors:
ABSTENSIONS/
VOTES IN FAVOR VOTES AGAINST/WITHHELD BROKER NON-VOTES
----------------- ------------------------- ----------------
Richard W. Fetzner 26,506,819 1,256,181 0
Garrett A. Garrettson 26,509,162 1,253,838 0
Peter J. Hill 27,110,912 652,088 0
Bruce M. McIntyre 26,509,412 1,253,588 0
Michael B. Wray 26,509,129 1,253,871 0
To approve the 2001 Long-Term Stock Incentive Plan:
Votes in Favor Votes Against/Withheld Abstentions/Broker Non-Votes
- -------------------- -------------------------- -------------------------------
16,265,425 2,371,951 13,593,860
2. To ratify the appointment of PricewaterhouseCoopers LLP as the
independent accountants for the year ended December 31, 2000.
ABSTENSIONS/
VOTES IN FAVOR VOTES AGAINST/WITHHELD BROKER NON-VOTES
----------------- ------------------------- -------------------
27,452,835 104,946 205,219
2001:
Votes in Favor Votes Against/Withheld Abstentions/Broker Non-Votes
- -------------------- -------------------------- -------------------------------
31,944,893 140,253 146,090
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27.1 Financial Data Schedule10.1 Amendment to Benton Oil and Gas Company Non-Employee
Director Stock Purchase Plan.
(b) Reports on Form 8-K
On June 6, 2000, the CompanyJuly 19, 2001, we filed a report on Form 8-K, under Item
5, "Other Events" regarding the appointment of Dr. Peter J.
Hill as President and Chief Executive Officertermination of the
Company.previously announced exchange offer and consent
solicitation.
On August 31, 2001, we filed a report on Form 8-K, under
Item 5, "Other Events" regarding the receipt of the
requisite consents to amend the indentures governing our
senior notes due in 2003 and 2007.
31
3137
SIGNATURES
Pursuant to the requirements of Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.
BENTON OIL AND GAS COMPANY
Dated: November 14, 200012, 2001 By: /S//s/ Peter J. Hill
------------------------------------------------------
Peter J. Hill
President and Chief Executive Officer
Dated: November 14, 200012, 2001 By: /S/David H. Pratt
------------------------------------
David H. Pratt/s/ Steven W. Tholen
---------------------
Steven W. Tholen
Senior Vice President of Finance and
Administration
and Chief Financial Officer