UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
Quarterly Report Pursuant to Section 13 or 15(d)
[X] of the Securities Exchange Act of 1934
For the Quarterly Period Ended September 30, 2001 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)
15835 PARK TEN PLACE DRIVE, SUITE 115
HOUSTON, TEXAS 77084
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (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 12, 2001, 33,946,919 shares of the
Registrant's Common Stock were outstanding.
2
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
Page
----
PART I FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets at September 30, 2001
and December 31, 2000 (Unaudited)........................................................3
Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 2001 and 2000 (Unaudited).....................................4
Consolidated Statements of Cash Flows for the Nine
Months Ended September 30, 2001 and 2000 (Unaudited).....................................5
Notes to Consolidated Financial Statements......................................................6
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS..............................................................22
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.......................................34
PART II OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS................................................................................36
Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS........................................................36
Item 3. DEFAULTS UPON SENIOR SECURITIES..................................................................36
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............................................36
Item 5. OTHER INFORMATION................................................................................36
Item 6. EXHIBITS AND REPORTS ON FORM 8-K.................................................................36
SIGNATURES...............................................................................................................37
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, unaudited)
SEPTEMBER 30, DECEMBER 31,
2001 2000
------------------ -----------------
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents $ 18,461 $ 15,132
Restricted cash 12 12
Marketable securities - 1,303
Accounts and notes receivable:
Accrued oil revenue 30,590 38,003
Joint interest and other, net 9,740
6,778
Prepaid expenses and other 1,562 2,404
------------ ------------
TOTAL CURRENT ASSETS 60,365 63,632
RESTRICTED CASH 16 10,920
OTHER ASSETS 5,059 5,891
DEFERRED INCOME TAXES 4,827 4,293
INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES 99,373 77,741
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of $17,935 and
$16,634 excluded from amortization in 2001 and 2000, respectively) 524,659 490,548
Furniture and fixtures 10,519 11,049
------------ ------------
535,178 501,597
Accumulated depletion, impairment and depreciation (395,677) (377,627)
------------ ------------
139,501 123,970
------------ ------------
$ 309,141 $ 286,447
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable, trade and other $ 4,198 $ 12,804
Accrued expenses 30,428 25,797
Accrued interest payable 9,480 3,733
Income taxes payable 10,200 3,214
Short-term borrowings - 5,714
Current portion of long-term debt 2,457 -
------------ ------------
TOTAL CURRENT LIABILITIES 56,763 51,262
LONG-TERM DEBT 221,598 213,000
OTHER LIABILITIES 1,138 -
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST 13,638 9,281
STOCKHOLDERS' EQUITY:
Preferred stock, par value $0.01 a share; authorized 5,000 shares;
outstanding, none - -
Common stock, par value $0.01 a share; authorized 80,000 shares;
issued 33,947 shares at September 30, 2001 and 33,872 shares at
December 31, 2000 339 339
Additional paid-in capital 156,874 156,629
Accumulated deficit (140,510) (143,365)
Treasury stock, at cost, 50 shares (699) (699)
------------
------------
TOTAL STOCKHOLDERS' EQUITY 16,004 12,904
------------ ------------
$ 309,141 $ 286,447
============ ============
See accompanying notes to consolidated financial statements.
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 2001 2000
------------- ------------ ------------- ------------
REVENUES
Oil and natural gas sales $ 31,370 $ 37,972 $ 98,552 $ 101,516
----------- ---------- ----------- -----------
31,370 37,972 98,552 101,516
----------- ---------- ----------- -----------
EXPENSES
Operating expenses 9,683 12,983 32,188 34,767
Depletion, depreciation and amortization 5,963 4,141 18,668 11,654
Write-downs of oil and gas properties and impairments - - 411 1,069
General and administrative 5,456 3,782 15,876 12,324
Taxes other than on income 1,243 1,364 4,369 3,460
----------- ---------- ----------- -----------
22,345 22,270 71,512 63,274
----------- ---------- ----------- -----------
INCOME FROM OPERATIONS 9,025 15,702 27,040 38,242
OTHER NON-OPERATING INCOME (EXPENSE)
Investment income and other 710 2,234 2,373 6,562
Interest expense (6,126) (7,318) (18,464) (22,228)
Net gain on exchange rates 297 67 516 200
----------- ---------- ----------- -----------
(5,119) (5,017) (15,575) (15,466)
----------- ---------- ----------- -----------
INCOME FROM CONSOLIDATED COMPANIES
BEFORE INCOME TAXES AND MINORITY INTERESTS 3,906 10,685 11,465 22,776
INCOME TAX EXPENSE 3,510 5,018 10,587 13,309
----------- ---------- ----------- -----------
INCOME BEFORE MINORITY INTERESTS 396 5,667 878 9,467
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
COMPANIES 1,523 2,007 4,357 4,978
----------- ---------- ----------- -----------
INCOME (LOSS) FROM CONSOLIDATED COMPANIES (1,127) 3,660 (3,479) 4,489
EQUITY IN NET EARNINGS OF AFFILIATED COMPANIES 2,859 2,213 6,334 4,117
----------- ---------- ----------- -----------
INCOME BEFORE EXTRAORDINARY INCOME 1,732 5,873 2,855 8,606
EXTRAORDINARY INCOME ON DEBT REPURCHASE,
NET OF TAX OF $0 - 3,095 - 3,095
----------- ---------- ----------- -----------
NET INCOME $ 1,732 $ 8,968 $ 2,855 $ 11,701
=========== ========== =========== ===========
NET INCOME PER COMMON SHARE:
Basic:
Income before extraordinary income $ 0.05 $ 0.19 $ 0.08 $ 0.29
Extraordinary income - 0.10 - 0.10
----------- ---------- ----------- -----------
Net income $ 0.05 $ 0.29 $ 0.08 $ 0.39
=========== ========== =========== ===========
Diluted:
Income before extraordinary income $ 0.05 $ 0.19 $ 0.08 $ 0.29
Extraordinary income - 0.10 - 0.10
----------- ---------- ----------- -----------
Net income $ 0.05 $ 0.29 $ 0.08 $ 0.39
=========== ========== =========== ===========
See accompanying notes to consolidated financial statements.
5
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands, unaudited)
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2001 2000
-------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 2,855 $ 11,701
Adjustments to reconcile net income to net cash provided by operating
activities: 18,668 11,654
Depletion, depreciation and amortization 411 1,069
Write-downs of oil and gas properties and impairments 944 1,047
Amortization of financing costs
Loss on disposal of assets -- 20
Equity in earnings of affiliated companies (6,334) (4,117)
Allowance for employee notes and accounts receivable 247 247
Non-cash compensation-related charges 245 --
4,357 4,978
Minority interest in undistributed earnings of subsidiaries
Extraordinary income from repurchase of debt -- (3,095)
(534) 36
Deferred income taxes
Changes in operating assets and liabilities:
Accounts and notes receivable 4,204 (8,754)
Prepaid expenses and other 842 1,010
Accounts payable (8,606) 8,042
Accrued expenses 4,631 7,711
Accrued interest payable 5,747 5,012
Income taxes payable 6,986 10,014
NET CASH PROVIDED BY OPERATING ACTIVITIES 34,663 46,575
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions of property and equipment (34,610) (40,127)
Investment in and advances to affiliated companies (15,298) (7,091)
Increase in restricted cash (57) (199)
Decrease in restricted cash 10,961 1,225
Purchase of marketable securities (15,067) (13,650)
Maturities of marketable securities 16,370 16,052
-------- --------
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) FINANCING ACTIVITIES 6,367 (2,816)
-------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3,329 (31)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 15,132 21,147
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 18,461 $ 21,116
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
$ 13,512 $ 14,749
Cash paid during the period for interest expense ======== ========
Cash paid during the period for income taxes $ 1,711 $ 1,559
======== ========
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
During the nine months ended September 30, 2000, we repurchased $8 million face
value of our senior unsecured notes with the issuance of 2,710,590 shares of
common stock.
See accompanying notes to consolidated financial statements.
6
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2001 (UNAUDITED)
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
We engage in the exploration, development, production and management of oil and
gas properties. We 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 over which we have significant influence. All
intercompany profits, transactions and balances have been eliminated. We account
for our investment in Geoilbent, Ltd. ("Geoilbent") and Arctic Gas Company
("Arctic Gas") based on a fiscal year ending September 30 (see Note 2).
INTERIM REPORTING
In our opinion, 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, 2001, and the
results of operations for the three and nine month periods ended September 30,
2001 and 2000 and cash flows for the nine month periods ended September 30, 2001
and 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 our consolidated financial statements and
notes thereto included in our Annual Report on Form 10-K for the year ended
December 31, 2000, for additional disclosures, including a summary of our
accounting policies.
The results of operations for the three and nine month periods ended September
30, 2001 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 us 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 $6.4 million and
$6.2 million at September 30, 2001 and December 31, 2000, respectively (see Note
11). Allowance for doubtful accounts related to joint interest and other
accounts receivable was $0.3 million at December 31, 2000.
MINORITY INTERESTS
We record a minority interest attributable to the minority shareholders of our
subsidiaries. The minority interests in net income and losses are generally
subtracted or added to arrive at consolidated net income.
MARKETABLE SECURITIES
Marketable securities are carried at amortized cost. The marketable securities
we may purchase are limited to those defined as Cash Equivalents in the
indentures for our 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. Our marketable securities at cost, which approximates fair
value, consisted of $1.3 million of commercial paper at December 31, 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. We did not
have any items of other comprehensive income during the three and nine month
periods ended September 30, 2001 or September 30, 2000 and, in accordance with
SFAS 130, have 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 structures. The numerator
(income), denominator (shares) and amount of the basic and diluted earnings per
share computations for income were (in thousands, except per share amounts):
AMOUNT PER
INCOME SHARES SHARE
------------- ------------ ------------
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001
---------------------------------------------
BASIC EPS
Income attributable 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 attributable to common stockholders $ 5,873 30,531 $ 0.19
======== ========= ========
8
AMOUNT PER
INCOME SHARES SHARE
------------- ------------ ------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001
--------------------------------------------
BASIC EPS
Income attributable to common stockholders $ 2,855 33,945 $ 0.08
======== ======== ========
Effect of dilutive securities:
Stock options and warrants - 68
-------- --------
DILUTED EPS
Income attributable to common stockholders 2,855 34,013 $ 0.08
======== ======== ========
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
--------------------------------------------
BASIC EPS
Income attributable to common stockholders $ 8,606 29,865 $0.29
======== ======== ========
Effect of dilutive securities:
Stock options and warrants - 243
-------- --------
DILUTED EPS
Income attributable to common stockholders $ 8,606 30,108 $0.29
======== ======== ========
An aggregate of 7.8 million and 5.6 million shares 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 month periods ended September 30, 2001 and 2000, respectively. An
aggregate of 6.7 million and 5.7 million shares 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 nine month periods ended September 30, 2001 and 2000, respectively.
PROPERTY AND EQUIPMENT
We 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 $0.6 million and $0.4 million for the nine months ended September 30, 2001
and 2000, respectively, and capitalized interest of $0.7 million and $0.4
million for the nine months ended September 30, 2001 and 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 $17.9 million and $16.6 million at September 30, 2001 and
December 31, 2000, respectively. We regularly evaluate our unproved properties
on a country by country basis for possible impairment. If we 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.
Substantially all of the excluded costs at September 30, 2001 and December 31,
2000 relate to the acquisition of Benton Offshore China Company and 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. The ultimate timing of when the costs related to the acquisition of
Benton Offshore China Company will be included in amortizable costs is
uncertain.
All capitalized costs and estimated future development costs (including
estimated dismantlement, restoration and abandonment costs) of proved reserves
are depleted using the units of production method based on the total proved
reserves of the country cost center. Depletion expense, which was substantially
all attributable to the Venezuelan cost center, for the nine months ended
September 30, 2001 and 2000, was $15.6 million and $10.2 million ($2.12 and
$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 five years.
Leasehold improvements are depreciated over the life of the applicable lease.
Depreciation expense was $3.0 million and $1.3 million for the nine months ended
September 30, 2001 and 2000, respectively. Additionally, as a result of the
reduction in force and corporate 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 June 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
anticipated 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
$0.5 million of which are included in depletion, depreciation and amortization.
The implementation of the plan was substantially complete by the end of the
third quarter of 2001. From June through September 2001, 21 employees were
terminated and $0.7 million in severance payments were paid. As of September 30,
2001, the accrued expenses associated with the reduction in force and corporate
restructuring plan, including anticipated costs to terminate the building lease
of the former Carpinteria, California headquarters office of $0.8 million, were
$1.0 million. The accrued expenses are expected to be paid by the end of the
first quarter of 2002.
RECLASSIFICATIONS
Certain items in 2000 have been reclassified to conform to the 2001 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 we 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 2001 2000 2001 2000
---------- ---------- ----------- ---------- ---------- ----------
Investments
Equity in net assets $ 28,056 $ 28,056 $(2,558) $(2,218) $ 25,498 $ 25,838
Other costs, net of amortization (103) (202) 28,127 19,058 28,024 18,856
---------- ---------- ----------- ---------- ---------- ----------
Total investments 27,953 27,854 25,569 16,840 53,522 44,694
Advances - - 28,466 21,986 28,466 21,986
Equity in earnings (losses) 19,134 12,310 (1,749) (1,249) 17,385 11,061
---------- ---------- ----------- ---------- ---------- ----------
Total $ 47,087 $ 40,164 $ 52,286 $ 37,577 $ 99,373 $ 77,741
========== ========== =========== ========== ========== ==========
10
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
---------------- ----------------
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. 108,000 108,000
Note payable with interest at 8.7%.
See description below. 5,400 -
Note payable with interest at 21%.
See description below. 5,655 -
---------------- ----------------
224,055 213,000
Less current portion 2,457 -
---------------- ----------------
$ 221,598 $ 213,000
================ ================
In November 1997, we issued $115 million in 9.375 percent senior unsecured notes
due November 1, 2007 ("2007 Notes"), of which we subsequently repurchased $10
million at their par value. In May 1996, we issued $125 million in 11.625
percent senior unsecured notes due May 1, 2003 ("2003 Notes"), of which we
repurchased $17 million at their discounted value in September 2000 and November
2000 with the issuance of 4.2 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, 2001, we were in compliance with all covenants of the
indentures.
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, with an original principal
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 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 2000, our equity and public debt values have eroded significantly. In
order to effectuate the changes necessary to restore our financial flexibility
and to 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 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 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 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 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.
Additionally, we have implemented a plan 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. 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.
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 (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, 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
response 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 operations by approximately $0.8 million
based on our third quarter production rates and cost structure.
12
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. In January 2001, Benton-Vinccler borrowed 5.4 billion Bolivars
(approximately $7.7 million) under this facility, which it 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. At September 30, 2001, the
facility had no outstanding balance.
We have significant debt principal obligations payable in 2003 and 2007. During
September 2000, we exchanged 2.7 million shares of our common stock, plus
accrued interest, for $8 million face value of our 11.625 percent senior notes
due in 2003 and purchased $5 million face value of our 2003 senior 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 $4 million face value of our 11.625 percent senior notes due in 2003.
We may exchange additional 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 stockholders 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.
If our future cash requirements are greater than our financial resources, we
intend to develop sources of additional capital and/or reduce our 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
the 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 expenditures, substantially all of which are
within our discretion; form joint ventures or alliances with financial or other
industry partners; sell 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 or 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 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 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.
In May 1996, we entered into an agreement with Morgan Guaranty that provided for
an $18 million cash collateralized five-year letter of credit to secure our
performance of the minimum exploration work program required on the Delta Centro
Block in Venezuela. As a result of expenditures made related to the exploration
work program, the letter of credit had been reduced to $7.7 million. In January
2001, we and our bidding partners reached an agreement to terminate the
remainder of the exploration work program in exchange for the unused portion of
the standby letter of credit of $7.7 million.
In March 2001, Benton-Vinccler submitted a claim to PDVSA for approximately $16
million seeking recovery for the value of oil quality adjustments made by PDVSA
to the oil delivered by Benton-Vinccler since production began at the South
Monagas Unit in 1993. We believe that we have a contractual basis for the claim
as the oil quality adjustments are not in conformity with the delivery
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 claim. Any compensation from PDVSA related to this matter
will be recorded in the period in which PDVSA confirms our claim.
Benton-Vinccler produces natural gas associated with the production of oil in
the South Monagas Unit. A portion of the natural 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
liability based on rates previously charged by PDVSA. It is uncertain when a
final agreement regarding the payment 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 our
financial position, results of operations or liquidity.
We have employment contracts with three senior management personnel which
provide for annual base salaries, bonus compensation and various benefits. The
contracts provide for the continuation of salary and benefits for the respective
terms of the agreements in the event of termination of employment without cause.
These agreements expire at various times from December 31, 2002 to July 9, 2003.
We have entered into equity acquisition agreements in Russia which call for us
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).
We 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. We lease 17,500 square feet of space in a building
that we no longer occupy under a lease agreement that expires in December 2004;
all of this office space has been subleased for rents that approximate our lease
costs. Additionally, we lease 51,000 square feet of space in a building formerly
used as our headquarters office in Carpinteria, California, for approximately
$79,000 per month under a lease agreement that expires in August 2013. We have
subleased 31,000 square feet of office space in this building for approximately
$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
Benton-Vinccler pays municipal taxes of approximately 3.6 percent of operating
fee revenues it receives for production from the South Monagas Unit. We 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, 2001 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 the 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 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, 2000, we had, for federal income tax purposes, operating loss
carryforwards of approximately $103 million expiring in the years 2003 through
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, 2001, we recorded deferred tax assets generated from
current period operating losses and a valuation allowance of $4.7 million.
We 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 our ongoing business.
15
NOTE 6 - OPERATING SEGMENTS
We regularly allocate resources to and assess the performance of our 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,
-------------------------------------- ---------------------------------------
(in thousands) 2001 2000 2001 2000
-------------- ----------------- ---------------- ----------------
OPERATING SEGMENT REVENUES
Oil and natural gas sales:
Venezuela $31,370 $37,796 $98,552 $101,189
United States and other -- 176 -- 327
-------------- ----------------- ---------------- ----------------
Total oil and gas sales 31,370 37,972 98,552 101,516
-------------- ----------------- ---------------- ----------------
OPERATING SEGMENT INCOME (LOSS)
Venezuela 6,056 7,964 16,949 20,011
Russia 2,557 1,821 5,462 2,695
United States and other (6,881) (817) (19,556) (11,005)
-------------- ----------------- ---------------- ----------------
Net income (loss) $1,732 $8,968 $2,855 $11,701
============== ================= ================ ================
SEPTEMBER 30, DECEMBER 31,
2001 2000
----------------- -----------------
OPERATING SEGMENT ASSETS
Venezuela $181,529 $166,462
Russia 100,028 78,406
United States and other 127,832 156,780
-------------- -----------------
Subtotal 409,389 401,648
Intersegment eliminations (100,248) (115,201)
-------------- -----------------
Total assets $309,141 $286,447
============== =================
16
NOTE 7 - RUSSIAN OPERATIONS
GEOILBENT
We own 34 percent of Geoilbent, a Russian limited liability company formed in
1991 that develops, produces and markets crude oil from the North Gubkinskoye,
Prisklonovoye and South Tarasovskoye Fields in the West Siberia region of
Russia. Our 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 were 3,751,788 barrels and 3,136,810 barrels, respectively. Prices
for crude oil for the nine months ended June 30, 2001 and 2000 averaged $19.06
and $15.70 per barrel, respectively. Depletion expense attributable to Geoilbent
for the nine months ended June 30, 2001 and 2000 was $2.65 and $2.20 per barrel,
respectively. Unaudited financial information for Geoilbent follows (in
thousands). All amounts represent 100 percent of Geoilbent.
STATEMENTS OF INCOME:
THREE MONTHS ENDED NINE MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------------- -------------------------------
2001 2000 2001 2000
------------- ------------- -------------- -------------
Revenues $24,191 $20,748 $71,495 $49,270
------------- ------------- -------------- -------------
Oil sales 24,191 20,748 71,495 49,270
------------- ------------- -------------- -------------
Expenses
Operating expenses 2,770 2,669 7,572 6,941
Depletion, depreciation and amortization 3,538 2,418 9,942 6,896
General and administrative 1,406 1,216 3,581 2,357
Taxes other than on income 5,703 4,032 20,496 8,733
------------- ------------- -------------- -------------
13,417 10,335 41,591 24,927
------------- ------------- -------------- -------------
Income from operations 10,774 10,413 29,904 24,343
Other Non-Operating Income (Expense)
Other income (expense) 178 129 652 (245)
Interest expense (1,602) (1,610) (5,574) (5,187)
Net gain (loss) on exchange rates 44 (137) 482 (517)
------------- ------------- -------------- -------------
(1,380) (1,618) (4,440) (5,949)
------------- ------------- -------------- -------------
Income before income taxes 9,394 8,795 25,464 18,394
Income tax expense 2,053 1,927 5,393 4,318
------------- ------------- -------------- -------------
Net income $ 7,341 $ 6,868 $20,071 $14,076
============= ============= ============== =============
17
BALANCE SHEETS:
JUNE 30, SEPTEMBER 30,
2001 2000
------------ ------------
Current assets:
Cash and cash equivalents $ 1,763 $ 2,133
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 $ 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
============ ============
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
percent payable on January 27 and July 27 each year. Principal payments are due
in varying installments on the semiannual interest payment dates which began on
January 27, 2001 and end 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, dividends, mergers
and sales of assets. Geoilbent began borrowing under these facilities in October
1997 and had borrowed a total of $48.5 million through December 31, 2000. The
four-year loan amortization period began in January 2001, and through September
30, 2001 Geoilbent has repaid $10.5 million. The proceeds from the loans were
used by Geoilbent to develop the North Gubkinskoye and Prisklonovoye Fields in
West Siberia, Russia.
18
During 1996 and 1997, we 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 us for $2.6
million of such costs, which were then included in accounts receivable. During
2000, Geoilbent paid the accounts receivable.
In October 1995, Geoilbent entered into an agreement with Morgan Guaranty for a
credit facility under which we provide cash collateral for the loans to
Geoilbent. 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. In May 2001, Geoilbent entered into an
agreement with IMB to borrow $3.3 million to repay the Morgan credit facility
and, as 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 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 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.
ARCTIC GAS COMPANY
In April 1998, we signed an agreement to earn a 40 percent equity interest in
Arctic 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 blocks in West Siberia. The two blocks comprise 794,972 acres
within and adjacent to the Urengoy Field, Russia's largest producing natural gas
field. Under the terms of a Cooperation Agreement with Arctic Gas, we will earn
a 40 percent equity interest in exchange for providing the initial capital
needed to achieve economic self-sufficiency through its own oil and gas
production. Our 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, we have received voting shares
representing a 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, 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 right 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.
We account for our interest in Arctic Gas using the equity method due to the
significant influence we exercise over the operating and financial policies of
Arctic Gas. Our share in the losses of Arctic Gas were $0.5 million and $0.7
million for the nine month periods ended June 30, 2001 and 2000, respectively.
For the nine months ended June 30, 2001 and 2000, we had a weighted-average
equity interest of 29 percent and 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 us 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.
19
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 percent of Arctic Gas.
STATEMENTS OF OPERATIONS:
THREE MONTHS ENDED JUNE 30, NINE MONTHS ENDED JUNE 30,
------------------------------------ --------------------------------
2001 2000 2001 2000
------------- -------------- ------------- ------------
Oil Sales $ 3,547 $ 1,773 $ 6,988 $ 1,773
Expenses
Operating expenses (380) 867 1,855 1,157
Depletion, depreciation and amortization 420 45 733 237
General and administrative 790 600 2,086 1,452
Taxes other than on income 1,026 391 2,799 562
------------- -------------- ------------ ------------
1,856 1,903 7,473 3,408
------------- -------------- ------------ ------------
Income (loss) from operations 1,691 (130) (485) (1,635)
Other Non-Operating Income (Expense)
Net gain (loss) on exchange rates (23) 2 (305) (235)
Interest expense (461) (346) (1,226) (836)
------------
------------- -------------- ------------
(484) (344) (1,531) (1,071)
------------- -------------- ------------ ------------
Income (loss) before income taxes 1,207 (474) (2,016) (2,706)
Income tax expense (benefit) - - (189) -
------------- -------------- ------------ ------------
Net income (loss) $ 1,207 $ (474) $ (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)
NOTE 8 - VENEZUELA 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 Lagoven, S.A., then one of
three exploration and production affiliates of the national oil company,
Petroleos de Venezuela, S.A. 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 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. 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. Currently, we are in discussions with PDVSA regarding the appropriate
amount to
20
pay for natural gas produced from the South Monagas Unit and used as fuel in
Benton-Vinccler's operations as well as other operating issues.
In December 1999, we entered into agreements with Schlumberger and Helmerich &
Payne to further develop the South Monagas Unit pursuant to a long-term
incentive-based development program. Schlumberger has agreed to financial
incentives intended to reduce drilling costs, improve initial production rates
of new wells and to increase the average life of the downhole pumps at South
Monagas. As part of Schlumberger's commitment to the program, it provides
additional technical and engineering resources on-site full-time in Venezuela
and at our offices in Carpinteria, California. As of December 31, 2000, 26 new
oil wells and 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, we and our bidding partners, predecessor companies acquired
over time by Burlington Resources, Inc. ("Burlington") and Anadarko Petroleum
Corporation ("Anadarko"), were awarded the right to explore and develop the
Delta Centro Block in Venezuela. The contract required a minimum exploration
work program consisting of a seismic survey and the drilling of three wells
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 we and the other partners each post a performance
surety bond or standby letter of credit for our pro rata share of the estimated
work commitment expenditures. We had a 30 percent interest in the exploration
venture, with Burlington and Anadarko each owning a 35 percent interest. In July
1996, formal agreements were finalized and executed, and we posted an $18
million standby letter of credit, collateralized in full by a time deposit, to
secure 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, 2001, our
share of expenditures to date on the Delta Centro Block was $23.1 million.
NOTE 9 - UNITED STATES OPERATIONS
In April and May 2000, we 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 us. During the 18-month term of the exploration agreement, we
will reimburse Coastline for certain of its overhead and prospect evaluation
costs. Under the agreements, for prospects evaluated by Coastline that we
acquire, Coastline will receive compensation based (a) on 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, we
acquired an approximate 25 percent working interest in the East Lawson Field in
Acadia Parish, Louisiana. The acquisition included a 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 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, we acquired a 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 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 percent participation interest in the California Leases, we became the
operator of the project and agreed to pay 100 percent of the
21
first $3.7 million and 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, we 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. In the fourth quarter of 1999, we decided to focus
our capital expenditures on existing producing properties and fulfilling work
commitments associated with our other properties. Because we had no firm
approved plans to continue drilling on the California Leases and the 2199 #7
exploratory well did not result in commercial reserves, we 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, we 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 our 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 has, as our wholly owned subsidiary, continued as the
operator and contractor of WAB-21. Benton Offshore China Company has submitted
an exploration program and budget to CNOOC. However, due to certain territorial
disputes over the sovereignty of the contract area, it is unclear when such
program will commence.
NOTE 11 - RELATED PARTY TRANSACTIONS
From 1996 through 1998, we made unsecured loans to our then Chief Executive
Officer, A. E. Benton. Each of these loans was evidenced by a promissory note
bearing interest at the rate of 6 percent per annum. We 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 us by Mr. Benton exceeded the value of our
collateral, due to the decline in the price of our stock. As a result, we
recorded an allowance for doubtful accounts of $2.9 million. The portion of the
note secured by our 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. We recorded an additional $2.8 million allowance for
doubtful accounts for the remaining principal and accrued interest owed to us at
June 30, 1999, and continue to record additional allowances as interest accrues
($0.9 million for the period July 1, 1999 to September 30, 2001). Measuring the
amount of the allowances requires judgments and estimates, and the amount
eventually realized may differ from the estimate.
In February 2000, we entered into a Separation Agreement and a Consulting
Agreement with Mr. Benton, pursuant to which we retained Mr. Benton as an
independent contractor to perform certain services for us. Mr. Benton has agreed
to propose a plan of reorganization in his bankruptcy case that provides for the
repayment of our loans to him. Under the proposed plan, which we anticipate will
be submitted to the bankruptcy court in the fourth quarter of 2001 and
considered by the bankruptcy court in 2002, we will retain our security interest
in Mr. Benton's 600,000 shares of our stock and in his stock options. Repayment
of our loans to Mr. Benton may be achieved through Mr. Benton's liquidation of
certain real and personal property assets and a phased liquidation of stock
resulting from Mr. Benton's exercise of his stock options. The amount that we
eventually realize including Benton Oil and Gas Company stock and the timing of
receipt of payments will depend upon the timing and results of the liquidation
of Mr. Benton's assets.
For 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. Wray received $100,000 and will provide consulting
services on matters pertaining to our business and that of our affiliates
through December 31, 2001.
22
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
We 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 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, we
caution you that important factors could cause actual results to differ
materially from those in the forward-looking statements. Such factors include
our substantial concentration of operations in Venezuela and Russia, the
political and economic risks associated with international operations, the
anticipated future development costs for our 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, 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 described in our 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 RESTRICTIONS
As a result of our substantial leverage and disappointing financial results
prior to 2000, our equity and public debt values have eroded significantly. In
order to effectuate the changes necessary to restore our financial flexibility
and to 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 repurchase 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 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 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. 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 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 anticipated loss on subleasing
the Carpinteria headquarters and $0.4 million for the reduction in the carrying
value of fixed assets that were not transferred to Houston. The implementation
of the plan 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 our existing assets in Venezuela and Russia, or the
sale of the Company. 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 our consolidated
financial statements and reflect the 20 percent ownership interest of Vinccler
as a minority interest. We account for our investments in Geoilbent and Arctic
Gas using the equity method. We include Geoilbent and Arctic Gas in our
consolidated financial statements based on a fiscal year ending September 30.
Accordingly, our results of operations for the nine months ended September 30,
2001 and 2000 reflect results from Geoilbent and Arctic Gas for the nine months
ended June 30, 2001 and 2000, respectively.
We follow the full-cost method of accounting for our investments in oil and gas
properties. We capitalize all acquisition, exploration, and development costs
incurred. We account for our oil and gas properties using cost centers on a
country by country basis. We credit proceeds from sales of oil and gas
properties to the full-cost pools 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 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 that 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; and
- estimated dismantlement, restoration and abandonment costs (see Note 1
of the "Notes to the Consolidated Financial Statements" for additional
information).
You should read the following discussion of the results of operations for the
three and nine months ended September 30, 2001 and 2000 and the financial
condition as of September 30, 2001 and December 31, 2000 in conjunction with our
Consolidated Financial Statements and related Notes thereto included in PART I,
Item 1, "Financial Statements." The 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 in Venezuela, which
accounted for all of our production and oil sales revenue. As a result of
decreased world crude oil prices, oil sales in Venezuela were 17 percent lower
in 2001 compared with 2000. Realized fees per barrel decreased 17 percent (from
$15.81 in 2000 to $13.15 in 2001) and oil sales quantities were substantially
unchanged (2.4 million barrels of oil in 2000 and 2001). Our operating expenses
from the South Monagas unit decreased 22 percent primarily due to decreased
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 amortization expense of $6.0 million;
- general and administrative 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
- minority interest of $1.5 million.
Other items of income consisted of:
- investment income and other of $0.7 million;
- net gain on exchange rates of $0.3 million; and
- 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. The expenses we incurred during the period consisted of:
- operating expenses of $13.0 million;
- depletion, depreciation and amortization expense of $4.1 million;
- general and administrative expense of $3.8 million;
- taxes other than on income of $1.4 million;
- interest expense of $7.3 million;
- income tax expense of $5.0 million; and
- minority interest of $2.0 million.
Other items of income consisted of:
- investment income and other of $2.2 million;
- net gain on exchange rates of $0.1 million;
- equity in net earnings of affiliated companies of $2.2 million; and
- extraordinary gain on the repurchase of long-term notes of $3.1
million.
Our net income was $9.0 million or $0.29 per share (diluted).
Our revenues decreased $6.6 million, or 17 percent, during the three months
ended September 30, 2001 compared with 2000. This was due to decreased oil sales
revenue in Venezuela as a result of decreased world crude oil prices. Our sales
quantities for the three months ended September 30, 2001 from Venezuela were 2.4
million barrels (25,900 barrels of oil per day) compared with 2.4 million
barrels (26,000 barrels of oil per day) for the three months ended September 30,
2000. Prices for crude oil averaged $13.15 per barrel (pursuant to terms of an
operating service agreement) from Venezuela during the three months ended
September 30, 2001 compared with $15.81 per barrel during the three months ended
September 30, 2000.
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 decreased workover costs, 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 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, and the estimated costs to terminate the building lease of the
former Carpinteria, California headquarters office of $0.5 million. Depletion
expense per barrel of oil produced from Venezuela during the three months ended
September 30, 2001 was $2.12 compared with $1.49 during 2000. General and
administrative expenses increased $1.7 million, or 45 percent, during the three
months ended September 30, 2001 compared with 2000. This was primarily due to
consent fee payments and legal fees totaling $1.2 million associated with the
amendment of indenture covenants of our senior unsecured notes and the estimated
costs to terminate the building lease of the former Carpinteria, California
headquarters office of $0.8 million. Taxes other than on income decreased $0.2
million, or 14 percent, during the three months ended September 30, 2001
compared with the three months ended September 30, 2000 primarily due to reduced
oil sales resulting from lower world crude oil prices.
25
Investment income and other decreased $1.5 million, or 68 percent, during the
three months ended September 30, 2001 compared with 2000, primarily due to lower
average restricted cash and marketable securities balances. Interest expense
decreased $1.2 million, or 16 percent, during the three months ended September
30, 2001 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, 2001 compared with 2000 due to changes in the value of the
Bolivar. We realized income before income taxes and minority interest of $3.9
million during the three months ended September 30, 2001 compared with income of
$10.7 million in 2000, resulting in decreased income tax expense of $1.5
million. The effective tax rate of 90 percent varies from the U.S. statutory
rate of 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
decreased $0.5 million for the three months ended September 30, 2001 compared
with 2000, primarily due to the decreased profitability of Benton-Vinccler.
Equity in net earnings of affiliated companies increased $0.7 million, or 32
percent, during the three months ended September 30, 2001 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 June 30,
2001 compared with earnings of $2.3 million for 2000. The increase of $0.2
million, or 8 percent, was primarily due to increased sales quantities and world
crude oil prices partially offset by increased depletion and taxes other than on
income. Prices for Geoilbent's crude oil averaged $19.01 per barrel during the
three months ended June 30, 2001 compared with $17.19 per barrel for the three
months ended June 30, 2000. Our share of Geoilbent oil sales quantities
increased by 22,335 barrels, or 5 percent, from 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
We had revenues of $98.6 million for the nine months ended September 30, 2001.
The expenses 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. The expenses we incurred during the period consisted of:
- operating expenses of $34.8 million;
- depletion, depreciation and amortization expense of $11.7 million;
- write-downs of oil and gas properties and impairments of $1.1 million;
- general and administrative expense of $12.3 million;
- taxes other than on income of $3.5 million;
- interest expense of $22.2 million;
- income tax expense of $13.3 million; and
- minority interest of $5.0 million.
26
Other items of income consisted of:
- investment income and other of $6.6 million;
- net gain on exchange rates of $0.2 million;
- equity in net earnings of affiliated companies of $4.1 million; and
- extraordinary gain on the repurchase of long-term notes of $3.1
million.
Our net income was $11.7 million or $0.39 per share (diluted).
Our revenues decreased $2.9 million, or 3 percent, during the nine months ended
September 30, 2001 compared with 2000. This was due to decreased oil sales
revenue in Venezuela as a result of decreases in world crude oil prices
substantially offset by increased sales quantities. Our sales quantities for the
nine months ended September 30, 2001 from Venezuela were 7.4 million barrels
(27,000 barrels of oil per day) compared with 6.9 million barrels (25,100
barrels of oil per day) for the nine months ended September 30, 2000. The
increase in sales quantities of 481,055 barrels, or 7 percent, was primarily due
to the infill drilling program that began in January 2000 and ended in December
2000. Prices for crude oil averaged $13.39 per barrel (pursuant to terms of an
operating service agreement) from Venezuela during the nine months ended
September 30, 2001 compared with $14.71 per barrel during the nine months ended
September 30, 2000.
Our operating expenses decreased $2.6 million, or 7 percent, during the nine
months ended September 30, 2001 compared with the nine months ended September
30, 2000. This was primarily due to decreased workover costs substantially
offset by a 7 percent increase in oil 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
barrel of oil produced from Venezuela during the nine months ended September 30,
2001 was $2.12 compared with $1.48 during 2000. We recognized write-downs of
$0.4 million and $1.1 million at September 30, 2001 and 2000, 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, 2001 compared with
2000. This was primarily due to severance and termination benefits for 27
employees of $0.9 million associated with the reduction in force and corporate
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 26 percent, during the
nine months ended September 30, 2001 compared with the nine months ended
September 30, 2000 primarily due to a one-time municipal tax adjustment due to a
change in tax rates at the South Monagas Unit in Venezuela, substantially offset
by decreased oil sales revenue.
Investment income and other decreased $4.2 million, or 64 percent, during the
nine months ended September 30, 2001 compared with 2000, primarily due to lower
average restricted cash and marketable securities balances. Interest expense
decreased $3.7 million, or 17 percent, during the nine months ended September
30, 2001 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 $0.3 million for the nine months ended
September 30, 2001 compared with 2000 due to changes in the value of the
Bolivar. We realized income before income taxes and minority interests of $11.5
million during the nine months ended September 30, 2001 compared with income of
$22.8 million in 2000, resulting in decreased income tax expense of $2.7
million. The effective tax rate of 92 percent varies from the U.S. statutory
rate of 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
decreased $0.6 million for the nine months ended September 30, 2001 compared
with 2000, primarily due to the decreased profitability of Benton-Vinccler.
Equity in net earnings of affiliated companies increased $2.2 million, or 54
percent, during the nine months ended September 30, 2001 compared with 2000.
This was primarily due to increased income from Geoilbent and decreased losses
from Arctic Gas. Our
27
share of earnings from Geoilbent was $6.8 million for the nine months ended June
30, 2001 compared with earnings of $4.8 million for 2000. The increase of $2.0
million, or 42 percent, was due to higher world crude oil prices and increased
sales quantities. Prices for Geoilbent's crude oil averaged $19.06 per barrel
during the nine months ended June 30, 2001 compared with $15.70 per barrel for
the nine months ended June 30, 2000. Our share of Geoilbent oil sales quantities
increased by 209,093 barrels, or 20 percent, from 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
working 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 development 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
response 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 operations 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 year
2003 is highly dependent upon our success in pursuing some or all of the
strategic alternatives described above. There can be no assurance that 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, we entered into 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 evaluated prospects in the Gulf Coast area for possible acquisition
and development by us. During the 18-month term of the exploration agreement, we
reimbursed Coastline for certain of its overhead and prospect evaluation costs.
Under the agreements, for prospects evaluated by Coastline and that we acquire,
Coastline will receive compensation based on (a) oil and natural gas production
acquired or developed and (b) the profits, if any, resulting from the sale of
such prospects. In April 2000, pursuant to the agreements, we acquired an
approximate 25 percent working interest in the East Lawson Field in Acadia
Parish, Louisiana. The acquisition included a 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, we acquired a 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 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 percent participation interest in the California Leases, we became the
operator of the project and agreed to pay 100 percent of the first $3.7 million
and 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, we
entered into an agreement to acquire Molino Energy's interest in the California
Leases in exchange for the release of their joint interest billing obligations.
In the fourth quarter of 1999, we decided to focus our capital expenditures on
existing producing properties and fulfilling work commitments associated with
our other properties. Because we had no firm approved plans to continue drilling
on the California Leases and the 2199 #7 exploratory well did not result in
commercial reserves, we 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.
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 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.S. dollar as its functional currency. We cannot
predict the timing or impact of future devaluations in Venezuela.
In December 1996, we acquired Crestone Energy Corporation, a privately held
company headquartered in Denver, Colorado, subsequently renamed Benton Offshore
China Company. Its principal asset is a petroleum contract with China National
Offshore Oil Corporation ("CNOOC") for the WAB-21 area. The WAB-21 petroleum
contract covers 6.2 million acres in the South China Sea, with an option for an
additional 1.0 million acres under certain circumstances, and lies within an
area which is the subject of a territorial dispute between the People's Republic
of China and Vietnam. Vietnam has executed an agreement on a portion of the same
offshore acreage with Conoco Inc. The dispute has lasted for many years, and
there has been limited exploration and no development activity in the area under
dispute.
China'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, if at all,
this dispute will be resolved or whether it would result in our 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, 2001, we had recorded no proved reserves attributable to this
petroleum contract.
In April 1998, we signed an agreement to earn a 40 percent equity interest in
Arctic 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 blocks in West Siberia. The two blocks comprise 794,972 acres
within and adjacent to the Urengoy Field, Russia's largest producing natural gas
field. Under the terms of a Cooperation Agreement between us and Arctic Gas, we
will earn a 40 percent equity interest in exchange for providing the initial
capital needed to achieve the economic self-sufficiency through its own oil and
natural gas production. Our 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. Pursuant to the Cooperation
Agreement, we have received voting shares representing a 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 we exercise over the operating and financial policies of
Arctic Gas, we account for our 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 us 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.
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 right 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 purpose of developing, producing and
marketing crude oil from the 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
Our results of operations and cash flow are affected by changing oil prices.
However, our 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. This dampens both any upward and downward effects of changing
prices on our Venezuelan oil sales and cash flows. If the price of oil
increases, there could be an increase in our cost 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 our 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 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 us or 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 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, our 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, 2001, net foreign exchange gains
attributable to our Venezuelan operations were $0.5 million and net foreign
exchange gains attributable to our Russian operations were $0.2 million.
However, there are many factors affecting foreign exchange rates and resulting
exchange gains and losses, many of which are beyond our 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 we may be
affected by future changes in exchange rates and exchange controls.
34
Our operations are affected by political developments and laws and regulations
in the areas in which 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 our operations and results.
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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We 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, our 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. 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 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 $14.94 per barrel in 2000. During
the 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 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, we have
utilized hedging transactions with respect to a portion of our oil and natural
gas production to achieve a more predictable cash flow, as well as to reduce our
exposure to price fluctuations, but we 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. We 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, 2001 consisted of $213 million of
fixed-rate senior unsecured notes maturing in 2003 ($108 million) and 2007 ($105
million) and $11.1 million of floating-rate notes due in 2006. A hypothetical 10
percent adverse change in the floating rate would not have had a material affect
on our results of operations for the nine months ended September 30, 2001.
35
FOREIGN EXCHANGE
Our operations are located primarily outside of the United States. In
particular, our 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 U.S. dollars; expenditures are both in U.S.
dollars and local currency. For the Russian operations, a majority of the oil
sales are received in U.S. dollars; expenditures are both in U.S. dollars and
local currency, although a larger percentage of the expenditures are in local
currency. We have utilized no currency hedging programs to mitigate any risks
associated with operations in these countries, and therefore our financial
results are subject to favorable or unfavorable fluctuations in exchange rates
and inflation in these countries.
36
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At our Annual Meeting of Stockholders held on July 30, 2001, the
following items were voted on by the Stockholders in addition to the
election of directors:
1. 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, 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
10.1 Amendment to Benton Oil and Gas Company Non-Employee
Director Stock Purchase Plan.
(b) Reports on Form 8-K
On July 19, 2001, we filed a report on Form 8-K, under Item
5, "Other Events" regarding the termination of the
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.
37
SIGNATURES
Pursuant to the requirements of Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.
BENTON OIL AND GAS COMPANY
Dated: November 12, 2001 By: /s/ Peter J. Hill
------------------
Peter J. Hill
President and Chief Executive Officer
Dated: November 12, 2001 By: /s/ Steven W. Tholen
---------------------
Steven W. Tholen
Senior Vice President of Finance and
Administration
and Chief Financial Officer