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1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(MARK ONE)
Annual Report Under Section 13 or 15(d)
of the Securities Exchange Act of 1934
[X] For the fiscal year ended December 31, 2000 or
Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from __________ to __________
COMMISSION FILE NO.: 1-10762
-----------------------
BENTON OIL AND GAS COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 77-0196707
(STATE OR OTHER JURISDICTION OF (IRS Employer Identification Number)
INCORPORATION OR ORGANIZATION)
6267 CARPINTERIA AVENUE, SUITE 200
CARPINTERIA, CALIFORNIA 93013
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
Registrant's telephone number, including area code (805) 566-5600
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ------------------- -----------------------------------------
Common Stock, $.01 Par Value NYSE
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
- ------------------- -----------------------------------------
Common Stock Purchase Warrants, NASDAQ
$11.00 exercise price
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 [ ]
On March 28, 2001, the aggregate market value of the shares of voting stock of
Registrant held by non-affiliates was approximately $66,943,032 based on a
closing sales price on NYSE of $2.00
As of March 28, 2001, 33,946,919 shares of the Registrant's common stock were
outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 2001 Annual Meeting of
Stockholders to be filed with the Securities and Exchange Commission, not later
than 120 days after the close of its fiscal year, pursuant to Regulation 14A,
are incorporated by reference into Items, 10, 11, 12, and 13 of Part III of this
annual report.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.[ ]
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BENTON OIL AND GAS COMPANY
FORM 10-K
TABLE OF CONTENTS
Page
----
Part I
- ------
Item 1. Business.....................................................3
Item 2. Properties..................................................21
Item 3. Legal Proceedings...........................................21
Item 4. Submission of Matters to a Vote of Security Holders ........22
Part II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters.....................23
Item 6. Selected Consolidated Financial Data........................24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................26
Item 7A. Quantitative and Qualitative Disclosures about
Market Risk.........................................40
Item 8. Financial Statements and Supplemental Data..................40
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure .............40
Part III
Item 10. Directors and Executive Officers of the Registrant .........41
Item 11. Executive Compensation......................................41
Item 12. Security Ownership of Certain Beneficial
Owners and Management...........................41
Item 13. Certain Relationships and Related Transactions .............41
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.............................42
Financial Statements.......................................................44
Signatures.................................................................77
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PART I
The Company cautions that any forward-looking statements (as such term is
defined in the Private Securities Litigation Reform Act of 1995) contained in
this report or made by management of the Company involve risks and uncertainties
and are subject to change based on various important factors. When used in this
report, the words budget, budgeted, anticipate, expect, believes, goals or
projects and similar expressions are intended to identify forward-looking
statements. In accordance with the provisions of the Private Securities
Litigation Reform Act of 1995, the Company cautions that important factors could
cause actual results to differ materially from those in the forward-looking
statements. Such factors include the Company's substantial concentration of
operations in Venezuela, the political and economic risks associated with
international operations, the anticipated future development costs for the
Company's undeveloped proved reserves, the risk that actual results may vary
considerably from reserve estimates, the dependence upon the abilities and
continued participation of certain key employees of the Company, the risks
normally incident to the operation and development of oil and gas properties and
the drilling of oil and 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. See Risk Factors included in
Item 7 - Management's Discussion and Analysis of Financial Condition and Results
of Operations.
ITEM 1 BUSINESS
GENERAL
Benton Oil and Gas Company is an independent energy company which has been
engaged in the development and production of oil and gas properties since 1989.
We have developed significant interests in Venezuela and Russia, and have
acquired certain less significant interests in other parts of the world. Our
producing operations are conducted principally through our 80 percent-owned
Venezuelan subsidiary, Benton-Vinccler, C.A., which operates the South Monagas
Unit in Venezuela; and Geoilbent Ltd., a Russian limited liability company of
which we own 34 percent, which operates the North Gubkinskoye Field in West
Siberia, Russia. Additionally, we own 60 percent of the equity interest in
Arctic Gas Company, of which 31 percent was subject to restrictions on transfer
and 29 percent was not subject to restrictions on transfer, as of December 31,
2000. Arctic Gas was formed to explore and develop the Samburg and Yevo-Yakha
License Blocks in the West Siberian Basin of Russia. We have expanded into
projects which involve exploration components, such as opportunities in China,
through our acquisition of the WAB-21 Exploration Block and the Molino oil and
natural gas project in California.
As of December 31, 2000, we had total estimated proved reserves net of minority
interest of 172 MMBOE, and a standardized measure of discounted future net cash
flow, before income taxes, for total proved reserves of $583.1 million. Of these
totals, the South Monagas Unit represented 98 MMBbls and $368.4 million,
Geoilbent represented 33 MMBbls and $140.2 million, and Arctic Gas represented
41 MMBOE and $74.5 million.
As of December 31, 2000, we had total assets of $286.4 million. For the year
ended December 31, 2000, we had total revenues of $140.3 million, cash flows
from operations, before working capital changes, of $47.3 million, EBITDA of
$80.6 million and long-term debt of $213.0 million. For the year ended December
31, 1999, we had total revenues of $89.1 million, cash flows from operations,
before working capital changes, of $6.7 million, EBITDA of $29.9 million and
long-term debt of $264.6 million.
We currently have significant debt principal obligations payable in 2003 ($108
million) and 2007 ($105 million). Our debt service requirements may restrict our
ability to fund capital expenditures necessary to maximize the value of our
assets. The debt levels may restrict our ability to borrow additional monies to
fund asset growth or to provide financial flexibility. Additionally, our ability
to meet our debt obligations and to reduce our level of debt depends on our
future performance and crude oil and natural gas realizations. General economic
conditions and financial, business and other factors affect our operations and
our future performance. Many of these factors are beyond our control. If we are
unable to repay our debt at maturity out of cash on hand, we could attempt to
refinance such debt, or repay such debt with the proceeds of an equity offering.
Factors that will affect our ability to raise cash through an offering of our
capital stock or a refinancing of our debt include financial market conditions
and our value and performance at the time of such offering or other financing.
We cannot assure you that any such offering or refinancing can be successfully
completed.
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MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS
As a result of Benton's increased leverage and poor investment returns since
1998, 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 aimed at creating new
stockholder value, we undertook several significant actions beginning in 2000,
including:
- Hired a new President and Chief Executive Officer, a new Senior
Vice President and Chief Financial Officer and a new Vice
President and General Counsel;
- Reconstituted our Board of Directors with industry executives
with proven experience in oil and natural gas operations, finance
and international operations;
- Redefined our strategic priorities to focus on value creation;
- Initiated capital conservation steps and financial transactions
to de-leverage the company and improve cash flow for
reinvestment;
- Undertook a comprehensive study of our core Venezuelan asset to
attempt to enhance the value of its production, thus ultimately
increasing cash flow and potentially extending its productive
life.
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. 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 advisors, are
conducting a comprehensive review of strategic alternatives, including, but not
limited to, selling all or part of our existing assets in Venezuela and Russia,
debt restructuring, some combination thereof, 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.
OPERATING STRATEGY
Our long-term strategy is to identify and access large resources of hydrocarbons
in underexploited areas around the world that can be developed at low overall
finding and operating costs and converted into proved reserves, production and
value. To achieve this strategy, we must:
- restore our financial flexibility by restructuring our balance
sheet;
- exploit our core assets in Venezuela and Russia; and
- seek and exploit new oil and natural gas reserves.
With respect to our core Venezuelan assets, we intend to maximize the value of
production at the South Monagas Unit, rather than increase production at any
cost. As part of our strategic shift in focus on the value of the barrels
produced, we suspended the development drilling program for a period of
approximately six months starting in January 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 123 MMBbls (98 MMBbls net to Benton) of proved reserves of
oil in the fields. Our goal will be an accelerated development program with
lower cost production, starting from the second half of 2001, rising to an
expected level of up to between 31,000-33,000 Bbls of oil equivalent per day in
less than two years. This is based on current internal operating and financial
assumptions and also assumes that we do not enter into a transaction under which
we sell a significant portion of our assets, as described in "Item 1. Business -
Management, Operational and Financial Restrictions."
In the first half of 2001, we will concentrate on improving the production from
the existing 143 available wells in Venezuela. We achieved our goal of 30,000
barrels of oil per day in early January and in February production rose to over
33,000 BBls of oil per day. Currently, production (as of March 23, 2001) is
28,500 Bbls of oil per day which is expected to decline to between 25,000 and
26,000 barrels of oil per day by mid-year, then increase when the new
development plan commences in the third quarter. We expect to average
approximately 28,500 Bbls of oil per day for the first quarter of 2001.
The 2001 Venezuela capital budget includes $13.5 million for the construction of
a 31-mile oil pipeline with a capacity of 20,000 Bbls per day that will connect
the Tucupita Field production facility with the Uracoa central processing unit.
This is expected to reduce Tucupita Field operating costs over $2.50 per Bbl and
improve the infrastructure network to allow the future, efficient development of
the Bombal Field. Funding for construction of the pipeline was provided by two
loans funded by a Venezuelan bank in March 2001 totaling $12.3 million. 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 5 years. The
second loan, in the amount of 4.4 billion Venezuelan Bolivars
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5
($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 initial quarterly period is 16.5%.
In Russia, Geoilbent produced an average of 10,500 Bbls of oil per day in 2000
and is currently producing (as of March 23, 2001) 15,000 Bbls of oil per day. In
2001, Geoilbent will concentrate on increasing production, building a natural
gas pipeline to take flared natural gas to market and improving profitability.
Geoilbent is self-funding and although it has not paid dividends to its
shareholders in the past, the management of Geoilbent has informed us that it
expects to pay a dividend to its shareholders beginning in 2001, including
Benton Oil and Gas Company. However, any such action by Geoilbent would require
the consent of at least one other Geoilbent shareholder and may be subject to
other regulatory and contractual restrictions.
Our plan for Arctic Gas includes continuing to expand production of oil and
condensate through the recompletion of existing wells, building facilities and
pipelines to optimize delivery of liquids and initiating the production and sale
of natural gas in 2002. We intend to seek long-term contracts for oil,
condensate and natural gas production in both export and domestic Russian
markets. The goal at Arctic Gas is to preserve a controlling equity position and
seek financial and technical partnerships to enable paced, large-scale
development of the Samburg and Yevo-Yakha license blocks.
Over the long-term, we intend to continue to seek and exploit new oil and
natural gas reserves in current areas of interest while minimizing the
associated financial and operating risks. To reduce these risks, not only in
seeking new reserves but also with respect to our existing operations, we:
- Focus Our Efforts in Areas of Low Geologic Risk: We intend to
focus our exploration and development activities only in areas of
known, proven hydrocarbons.
- Use Proven Advanced Technology in Both Exploration and
Development: We use 3-D seismic technology, which produces a
three dimensional image of the earth's subsurface through the
computer's interpretation of seismic data. This technology
provides a more detailed understanding of the subsurface than
conventional surveys, which contributes significantly to field
appraisal, development and production.
- Establish a Local Presence Through Joint Venture Partners and the
Use of Local Personnel: We seek to establish a local presence in
our areas of operation to facilitate stronger relationships with
local government and labor. In addition, using local personnel
helps us to take advantage of local knowledge and experience and
to minimize costs.
- Commit Capital in a Phased Manner to Limit Total Commitments at
Any One Time: We often agree to minimum capital expenditure or
development commitments at the outset of new projects, but we
endeavor to structure such commitments so that we can fulfill
them over time, thereby limiting our initial cash outlay.
In pursuing new opportunities, we will seek to enter at an early stage and find
investment partners at the point of maximum value in an effort to reduce our
risk in any one venture. We also will continue to assess project value
regularly, preparing to monetize assets as opportunities arise.
OPERATIONS
The following table summarizes our proved reserves, drilling and production
activity, and financial operating data by principal geographic area at and for
each of the years ended December 31. All Venezuelan reserves are attributable to
an operating service agreement between Benton-Vinccler and Petroleos de
Venezuela, S.A. under which all mineral rights are owned by the Government of
Venezuela. Geoilbent and Arctic Gas Company are accounted for under the equity
method and have been included at their respective ownership interest in our
consolidated financial statements. Our year end financial information contains
results from our Russian operations based on a twelve-month period ending
September 30. Accordingly, our results of operations for the years ended
December 31, 2000, 1999 and 1998 reflect results from Geoilbent for the twelve
months ended September 30, 2000, 1999 and 1998, and from Arctic Gas for the
twelve months ended September 30, 2000.
We own 80 percent of Benton-Vinccler. The reserve information includes reserve
information net of a 20 percent deduction for the minority interest in
Benton-Vinccler. Drilling and production activity and financial data are
reflected without deduction for minority interest.
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BENTON-VINCCLER
-----------------------
YEAR ENDED DECEMBER 31,
-----------------------
2000 1999 1998
---- ---- ----
(DOLLARS IN 000'S)
RESERVE INFORMATION:
Proved reserves (MBbls) ................................................. 98,431 107,969 110,268
Discounted future net cash flow attributable to proved
reserves, before income taxes ......................................... $ 368,464 $ 521,346 $ 49,964
Standardized measure of future net cash flows ........................... $ 284,549 $ 380,865 $ 49,964
DRILLING AND PRODUCTION ACTIVITY:
Gross wells drilled ..................................................... 26 2 16
Average daily production (Bbls) ......................................... 25,585 26,485 33,349
FINANCIAL DATA:
Oil and natural gas revenues ............................................ $ 139,890 $ 89,060 $ 82,215
Expenses:
Operating expenses and taxes other than
on income ........................................................... 46,848 38,839 39,075
Depletion ............................................................... 15,708 14,732 30,274
Write-down of oil and gas properties .................................... -- -- 153,800
Income tax expense (benefit) ............................................ 19,768 3,822 (21,392)
---------- ---------- ----------
Total expenses ........................................................ 82,324 57,393 201,757
---------- ---------- ----------
Results of operations from oil and
natural gas producing activities ...................................... $ 57,566 $ 31,667 $ (119,542)
========== ========== ==========
We own 34 percent of Geoilbent, which we account for under the equity method.
The following table presents our proportionate share of Geoilbent's proved
reserves, drilling and production activity, and financial operating data for
the twelve months ended September 30, 2000, 1999 and 1998.
GEOILBENT
---------
YEAR ENDED DECEMBER 31,
-----------------------
2000 1999 1998
---- ---- ----
(DOLLARS IN 000'S)
RESERVE INFORMATION:
Proved reserves (MBbls) .................................................... 32,615 36,415 31,053
Discounted future net cash flow attributable to proved
reserves, before income taxes ............................................ $140,160 $215,348 $49,546
Standardized measure of future net cash flows .............................. $114,725 $169,077 $43,248
DRILLING AND PRODUCTION ACTIVITY:
Gross wells drilled ........................................................ 39 28 31
Average daily production (Bbls) ............................................ 3,945 3,975 2,530
FINANCIAL DATA:
Oil and natural gas revenues ............................................... $ 25,202 $ 11,142 $ 8,059
Expenses:
Operating expenses and taxes other than
on income .............................................................. 9,548 4,274 4,445
Depletion .................................................................. 3,249 3,287 3,407
Write down of oil and gas properties ....................................... -- -- --
Income tax expense ......................................................... 3,215 442 9
-------- -------- -------
Total expenses ........................................................... 16,012 8,003 7,861
-------- -------- -------
Results of operations from oil and
natural gas producing activities ......................................... $ 9,190 $ 3,139 $ 198
======== ======== =======
As of December 31, 2000 and 1999, respectively, we owned, free of any sale
and/or transfer restrictions, 29 percent and 24 percent of the equity interests
in Arctic Gas, which we account for under the equity method. The following table
presents our proportionate share, free of sale and transfer restrictions, of
Arctic Gas's proved reserves, drilling and production activity, and financial
operating data for the twelve months ended September 30, 2000 and 1999. Arctic
Gas had no proved reserves or operating or financial activity attributable to
our interests prior to the period ended September 30, 1999.
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ARCTIC GAS COMPANY
------------------
YEAR ENDED DECEMBER 31,
-----------------------
2000 1999
---- ----
(DOLLARS IN 000'S)
RESERVE INFORMATION:
Proved reserves (MBOE) .................................................... 41,236 3,714
Discounted future net cash flow attributable to proved
reserves, before income taxes ........................................... $ 74,517 $ 8,241
Standardized measure of future net cash flows ............................. $ 56,880 $ 6,836
DRILLING AND PRODUCTION ACTIVITY:
Gross wells drilled ....................................................... -- --
Average daily production (BOE) ............................................ 1,154 --
FINANCIAL DATA:
Oil and natural gas revenues .............................................. $ 889 $ --
Expenses:
Operating expenses and taxes other than
on income ............................................................. 604 --
Depletion ................................................................. 78 --
--------- ---------
Total expenses .......................................................... 682 --
--------- ---------
Results of operations from oil and
natural gas producing activities ........................................ $ 207 $ --
========= =========
SOUTH MONAGAS UNIT, VENEZUELA (BENTON-VINCCLER)
GENERAL
In July 1992, Benton and Venezolana de Inversiones y Construcciones Clerico,
C.A., a Venezuelan construction and engineering company ("Vinccler"), signed a
20-year operating service agreement with Petroleo y Gas, S.A. ("PDVSA"), an
affiliate of Petroleos de Venezuela, S.A. to reactivate and further develop the
Uracoa, Tucupita and Bombal Fields. These fields comprise the South Monagas
Unit. At that time, we were one of three foreign companies ultimately awarded an
operating service agreement to reactivate existing fields by PDVSA. We were the
first U.S. company since 1976 to be granted such an oil field development
contract in Venezuela.
The oil and natural gas operations in the South Monagas Unit are conducted by
Benton-Vinccler, our 80 percent-owned subsidiary. The remaining 20 percent of
the outstanding capital stock of Benton-Vinccler is owned by Vinccler. Through
our majority ownership of stock in Benton-Vinccler, we make all operational and
corporate decisions related to Benton-Vinccler, subject to certain
super-majority provisions of Benton-Vinccler's charter documents related to:
- mergers;
- consolidations;
- sales of substantially all of its corporate assets;
- change of business; and
- similar major corporate events.
Vinccler has an extensive operating history in Venezuela. It provided
Benton-Vinccler with initial financial assistance and significant construction
services. Vinccler continues to provide ongoing assistance with governmental and
labor relations.
Under the terms of the operating service agreement, Benton-Vinccler is a
contractor for PDVSA. Benton-Vinccler 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. In addition, PDVSA maintains full ownership
of equipment and capital infrastructure following its installation.
Benton-Vinccler invoices PDVSA each quarter based on barrels of oil accepted by
PDVSA during the quarter, using quarterly adjusted contract service fees per
barrel. Benton-Vinccler receives its payments from PDVSA in U.S. dollars
deposited directly into a U.S. bank account. The operating service agreement
provides for Benton-Vinccler to receive an operating fee for each barrel of
crude oil delivered. It also provides Benton-Vinccler with the right to receive
a capital recovery fee for certain of its capital expenditures, provided that
such operating fee and capital recovery fee cannot exceed the maximum total fee
per barrel set forth in the agreement. The operating fee is subject to quarterly
adjustments to reflect changes in the special energy index of the U.S. Consumer
Price Index. The maximum total fee is subject to quarterly adjustments to
reflect changes in the average of certain world crude oil prices. Currently, we
are in discussions with PDVSA regarding the appropriate amount to 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.
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In December 1999, we entered into agreements with Schlumberger and Helmerich &
Payne to further develop the Unit pursuant to a long term incentive based
alliance program. The alliance program includes the drilling of up to 80 wells.
It provides for financial incentives for Schlumberger and Helmerich & Payne that
are intended to:
- reduce drilling costs;
- improve initial production rates of new wells; and
- increase the average life of the downhole pumps at South Monagas.
As part of Schlumberger's commitment to the program, it provides technical and
engineering resources on-site full-time in Venezuela and at our offices in
Carpinteria, California.
We drilled 26 oil wells in 2000. As part of our strategic shift in focus on the
value of the barrels produced, we suspended the development drilling program for
a period of approximately six months starting in January 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 123 MMBbls (98 MMBbls net to Benton)
of proved reserves of oil in the fields. Our goal will be an accelerated
development program with lower cost production, starting from the second half of
2001, rising to an expected level of up to between 31,000-33,000 Bbls of oil
equivalent per day in less than two years. This is based on current internal
operating and financial assumptions and also assumes that we do not enter into a
transaction under which we sell a significant portion of our assets, as
described in "Item 1. Business - Management, Operational and Financial
Restrictions.'
In the first half of 2001, we will concentrate on improving the production from
the existing 143 available wells in Venezuela. Production, currently (as of
March 23, 2001) at 28,500 Bbls of oil per day in Venezuela, is expected to
decline to between 25,000 and 26,000 Bbls of oil per day by mid-year, then
increase when the new development plan starts in the third quarter.
LOCATION AND GEOLOGY
The Unit extends across the southeastern part of the state of Monagas and the
southwestern part of the state of Delta Amacuro in eastern Venezuela. The Unit
is approximately 51 miles long and eight miles wide and consists of 157,843
acres, of which the fields comprise approximately one-half. At December 31,
2000, proved reserves attributable to our Venezuelan operations were 123,039
MBbls (98,431 MBbls net to Benton). This represented approximately 57 percent of
our proved reserves. Benton-Vinccler is primarily developing the Oficina sands
in the Uracoa Field. The Uracoa Field contains 72 percent of the Unit's proved
reserves. Benton-Vinccler has begun the development of the Tucupita and Bombal
Fields, which contain the remaining 28 percent of the Unit's reserves.
Benton-Vinccler is currently reinjecting the associated natural gas produced at
Uracoa back into the reservoir. We are currently in discussions with PDVSA to
sell the natural gas, although there is no assurance that any natural gas
contracts will result from the discussions.
DRILLING AND DEVELOPMENT ACTIVITY
Benton-Vinccler contracts with third parties for drilling and completion of
wells. In 2000, we drilled 26 wells.
URACOA FIELD
Benton-Vinccler has been developing the Unit since 1992, beginning with the
Uracoa Field. During March 2001 (through March 23), a total of approximately 114
wells were producing an average of approximately 22,300 Bbls of oil per day in
the Uracoa Field. The following table sets forth the Uracoa Field drilling
activity and production information for each of the quarters presented:
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WELLS DRILLED
------------- AVERAGE DAILY
VERTICAL HORIZONTAL PRODUCTION FROM FIELD (Bbls)
-------- ---------- ----------------------------
1998:
First Quarter .................................. - - 37,700
Second Quarter ................................. - - 32,600
Third Quarter .................................. 2 - 26,500
Fourth Quarter ................................. 3 3 25,900
1999:
First Quarter .................................. - - 24,300
Second Quarter ................................. - - 22,800
Third Quarter .................................. - - 21,300
Fourth Quarter ................................. - - 21,000
2000:
First Quarter .................................. 6 - 19,800
Second Quarter ................................. 9 1 20,500
Third Quarter .................................. 2 3 21,900
Fourth Quarter ................................. 2 3 23,100
Production rates began to decline in the fourth quarter of 1997 due to a
reduction in drilling activity, natural reservoir decline, and production
related problems. We ended drilling operations in the fourth quarter of 1997
because the initial development plan for the Uracoa Field was completed. Without
continuous drilling, reservoirs like those at the Uracoa Field initially
experience a sharp natural decline that decreases with time. This initial sharp
natural decline was aggravated during 1998 due to the impact of production
problems we experienced on certain wells and the degradation of the local
electrical power source. We identified solutions to the electrical power and
production related problems in 1998, but the installation of electrical power
generation facilities and remediation work on wells was required into 1999.
Additionally, we focused our efforts on the completion of a detailed geologic
and reservoir simulation study during 1998, which identified up to 80 new infill
and development well locations. Drilling resumed in the second half of 1998, but
we suspended it again in 1999 due to uncertainties in oil prices and cash flows.
We limited our capital expenditures during this period primarily to workovers
and remediation activities. 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 oil wells in the Uracoa Field under the alliance
agreements utilizing Schlumberger's technical and engineering resources.
The 1998 geologic and reservoir simulation study indicated the viability of at
least 80 additional primary infill wells in the Uracoa Field. Many of these new
locations are in underdeveloped sands where the model was used to optimize well
spacing and location. In the more developed areas of the field, we used the
model to verify the economic viability of infill locations. In the first quarter
of 2001, we began a comprehensive technical review of the South Monagas Unit
that includes the completion of an extensive geologic and reservoir computer
simulation study to optimize field management and the remaining development
drilling program. The computer simulation study will update and extend the 1998
study on a portion of the Uracoa Field to the entire South Monagas Unit. It will
incorporate all new geologic and reservoir information as well as the total
production and drilling history from the more mature Uracoa Field and the
underdeveloped Tucupita and Bombal Fields. We expect several benefits from the
study including an optimum production profile of oil and gas, a revised water
and natural gas injection strategy, more efficient development locations and
improved well completion techniques.
Since 1992, we have reactivated 15 previously drilled wells and drilled 142 new
wells in the Uracoa Field using modern drilling and completion techniques that
had not previously been utilized on the field. Of the new wells drilled, a total
of 126 wells, or 89 percent, have been completed and placed on production,
four of which were converted to injection wells. Additionally, six injection
wells have been drilled, two of which have been converted to producing wells.
We process the oil, water and natural gas we produce from the Uracoa Field in
the Uracoa central processing unit. We ship the processed oil via pipeline to
the PDVSA custody transfer point. We treat and filter produced water, and then
re-inject it into the aquifer to assist the natural water drive. We re-inject
natural gas into the natural gas cap for reservoir pressure maintenance. The
major components of this state-of-the-art process facility were designed in the
United States and installed by Benton-Vinccler. This process design is commonly
used in heavy oil production in the United States, but was not previously used
extensively in Venezuela to process crude oil of similar gravity or quality. The
current production facility has capacity to handle 60 MBbls of oil per day, 130
MBbls of water per day, and 50 MMcf of natural gas per day.
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In August 1999, Benton-Vinccler sold its recently-constructed power generation
facility located in the Uracoa Field for $15.1 million. Concurrently with the
sale, Benton-Vinccler entered into a long-term power purchase agreement with the
purchaser of the facility to provide for the electrical needs of the field
throughout the remaining term of the operating service agreement.
Benton-Vinccler's 2001 capital expenditure budget includes drilling
approximately 12 wells at an estimated cost of $16 million. Drilling additional
wells will depend on the results of the current field development plan and
reservoir computer study now underway, the results of the 2001 development
drilling program and the availability of capital.
TUCUPITA AND BOMBAL FIELDS
Before becoming inactive in 1987, the Tucupita Field had been substantially
developed. It had produced 67.1 MMBbls of oil, 34.7 MMBbls of water and 17.6 Bcf
of natural gas. Benton-Vinccler drilled a successful pilot horizontal well in
late 1996 to evaluate the remaining development potential of the Tucupita field.
This well has produced 1.8 MMBbls of oil at an average rate of 1,117 Bbls of oil
per day. The early success of this pilot horizontal well led to the drilling of
a second horizontal well in 1998. Initial oil rates from the horizontal wells
were encouraging, but water production soon increased sharply. As a result, we
changed the redevelopment strategy to include drilling deviated wells to allow
for more effective water shut-off. During the second half of 1998, we drilled
five deviated infill wells to target undepleted portions of the field. All five
wells encountered high oil saturations, with an average initial production rate
of 922 Bbls of oil per day. Additionally, we re-activated nine wells, bringing
production levels to 5,900 Bbls of oil per day.
In 1999, Benton-Vinccler drilled a well on the west portion of the Tucupita
Field to test the commercial viability of a previously undrilled fault block
identified using 3-D seismic data. The well proved to be non-commercial for oil
production; however, we will investigate the natural gas potential of this well.
We are reinjecting produced water from Tucupita into the aquifer to aid the
natural water drive, and we have been flaring the associated natural gas.
However, this associated natural gas will be used to help generate electric
power for the field in the first quarter of 2001. We are trucking the oil to the
Uracoa central processing unit where we process the oil and ship it by pipeline
to the custody transfer point.
We have identified 18 new well locations in undepleted portions of the Tucupita
Field. We anticipate additional viable wells once we complete a simulation study
for Tucupita. Moreover, our analysis of petrophysical and production data has
revealed significant behind-pipe recompletion potential in a deeper pay section
that was not a primary target during the earlier development of the field.
Currently, we have identified 14 wells with recompletion potential for
reactivation.
To date, we have drilled one well in the Bombal Field and reactivated another.
The Bombal Field is currently producing 340 Bbls of oil per day. Our future
plans include drilling up to 26 development wells and installing a processing
facility to separate the oil, water and natural gas. Initially, we will
re-inject the water and natural gas back into the reservoir. We are currently in
discussions with PDVSA to sell the natural gas, although there are no assurances
that gas contracts will result from these discussions.
As a result of our analysis of the potential in the Tucupita field, and for
environmental and safety reasons, we will begin construction of a $13.5 million,
31-mile, 20,000 Bbls per day capacity oil pipeline from Tucupita to the Uracoa
central processing unit that we expect to complete in late 2001. Once completed,
we would also use the pipeline to transport oil from the Bombal Field after the
construction of a connecting pipeline estimated to cost $4.5 million. Currently,
we are transporting crude oil by trucks from both Tucupita and Bombal. A
pipeline would significantly reduce our transportation costs from both fields
and allow us to produce increased volumes of oil more economically.
CUSTOMERS AND MARKET INFORMATION
Oil produced in Venezuela is delivered to PDVSA under the terms of an operating
service agreement for an operating service fee. Benton-Vinccler has constructed
a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA's
storage facility. This is the custody transfer point. The service agreement
specifies that the oil stream may contain no more than 1 percent base sediment
and water. Quality measurements are conducted both at Benton-Vinccler's
facilities and at PDVSA's storage facility. We are in the process of installing
a continuous flow measuring unit at our facility so that we can closely monitor
the quantities delivered to PDVSA. PDVSA provides Benton-Vinccler with a daily
acknowledgment regarding the amount of oil accepted during the previous day. At
the end of each quarter, Benton-Vinccler prepares an invoice to PDVSA for that
quarter's deliveries. PDVSA pays the invoice at the end of the second month
after the end of the quarter. Invoice amounts and payments are denominated in
U.S. dollars. Payments are wire transferred into Benton-Vinccler's account in a
commercial bank in the United States.
Natural gas produced by Benton-Vinccler is currently re-injected or used for
operations, although discussions to sell the natural gas to PDVSA have been
initiated. There are no assurances that natural gas contracts will result from
these discussions.
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EMPLOYEES; COMMUNITY RELATIONS
Benton-Vinccler seeks to employ nationals rather than bring expatriates into the
country. Presently, there are six full-time expatriates working with
Benton-Vinccler and 160 local employees. Benton-Vinccler also has conducted
community relations programs, providing medical care, training, equipment and
supplies, and support for local schools, in both states in which the unit is
located.
NORTH GUBKINSKOYE, RUSSIA (GEOILBENT)
GENERAL
In December 1991, the joint venture agreement forming Geoilbent was registered
with the Ministry of Finance of the USSR. Geoilbent's ownership is as follows:
- Benton owns 34 percent;
- Purneftegazgeologia owns 33 percent; and
- Purneftegaz owns 33 percent.
In November 1993, the agreement was registered with the Russian Agency for
International Cooperation and Development. Geoilbent was later re-chartered as a
limited liability company. We believe that we have developed a good relationship
with our co-founding shareholders and have not experienced any disagreements on
major operational matters. Geoilbent may only take action through a 67 percent
majority vote of its shareholders.
LOCATION AND GEOLOGY
Geoilbent develops, produces and markets crude oil from the North Gubkinskoye
Field in the West Siberia region of Russia, located approximately 2,000 miles
northeast of Moscow. 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. It is
surrounded by large proven fields. The field is a large anticlinal structure
with multiple pay sands. The development to date has focused on the BP 8, 9, 10,
11 and 12 reservoirs with minor development in the BP 6 and 7 reservoirs.
Geoilbent is currently flaring the produced natural gas in accordance with
environmental regulations, although it is exploring alternatives to market the
natural gas. Geoilbent also holds rights to three more license blocks comprising
1,189,757 acres.
DRILLING AND DEVELOPMENT ACTIVITY
Geoilbent commenced initial operations in the field during the third quarter of
1992 with the construction of a 37-mile oil pipeline and installation of
temporary production facilities. During March 2001 (through March 23),
approximately 103 wells were producing an average of approximately 15,000 Bbls
of oil per day.
The following table sets forth drilling activity and production information for
each of the quarters presented:
AVERAGE DAILY
WELLS DRILLED PRODUCTION FROM FIELD (Bbls)
------------- ----------------------------
1998:
First Quarter............................ 10 7,600
Second Quarter........................... 9 8,600
Third Quarter............................ 7 9,900
Fourth Quarter........................... 5 9,900
1999:
First Quarter............................ 5 10,500
Second Quarter........................... 6 11,400
Third Quarter............................ 8 13,000
Fourth Quarter........................... 9 13,200
2000:
First Quarter............................ 2 11,200
Second Quarter........................... 12 12,700
Third Quarter............................ 15 13,900
Fourth Quarter........................... 10 14,700
Production was constrained in the first quarter of 2000 due to damage to
production facilities resulting from a fire.
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Geoilbent contracts with third parties for drilling and completion of wells. To
date, 38 previously drilled wells have been reactivated and 153 wells have been
drilled in the field. A total of 129 wells, or 84 percent, have been completed
and placed on production, 20 of which were converted to water injection
wells. Each well is drilled to an average measured depth of approximately 9,000
feet and an average true vertical depth of 8,000 feet. The current production
facilities are operating at or near capacity and will need to be expanded to
accommodate production increases.
Geoilbent transports oil produced from the North Gubkinskoye Field to production
facilities constructed and owned by Geoilbent. It then transfers the oil to
Geoilbent's 37-mile pipeline which transports the oil from the North Gubkinskoye
Field south to the main Russian oil pipeline network.
Geoilbent has obtained financing through a $65 million parallel loan facility
for the development of the North Gubkinskoye Field from the European Bank for
Reconstruction and Development and the International Moscow Bank. A total of
$48.5 million has been advanced to date from the loan facility. Geoilbent has a
2001 budget which includes capital expenditures of approximately $39 million, of
which $28 million would be used to drill 55 wells in the North Gubkinskoye Field
and $11 million would be used for construction of production and other
facilities. Its budget also includes $11 million for principal payments on the
loan facility. This budget is expected to be funded from Geoilbent's cash flow
from operations.
CUSTOMERS AND MARKET INFORMATION
Geoilbent's 37-mile pipeline runs from the field to the main pipeline in the
area where Geoilbent transfers the oil to Transneft, the state oil pipeline
monopoly. Transneft then transports the oil to the western border of Russia for
export sales or to various domestic locations for non-export sales. Trading
companies such as Rosneffegasexport handle all export oil sales. All export
sales have been paid in U.S. dollars into Geoilbent's account in Moscow.
Domestic sales are paid in Russian Rubles. During 2000, Geoilbent sold
approximately 48 percent of its production in the export market and 52 percent
in the domestic market.
EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS
Geoilbent employs Russian nationals almost exclusively. Presently, there are two
full-time expatriates working with Geoilbent and 603 local employees. We have
conducted community relations programs, providing medical care, training,
equipment and supplies in towns in which Geoilbent personnel reside and also for
the nomadic indigenous population which reside in the area of oilfield
operations.
EAST URENGOY, RUSSIA (ARCTIC GAS COMPANY)
GENERAL
Arctic Gas Company, formerly Severneftegaz, was formed in 1992 as a private
company to explore and develop the Samburg and Yevo-Yakha License Blocks. The
Samburg and Yevo-Yakha License Blocks are located within the West Siberian
Basin, the world's largest sedimentary basin, which contains nearly one third of
the world's proved and probable natural gas reserves. Both license blocks occur
on the eastern flank of the giant Urengoy natural gas field, which currently
produces hydrocarbons from Cenomanian reservoirs. Under the terms of agreements
signed in April 1998, we acquired a 40 percent interest in Arctic Gas in return
for providing or arranging up to $100 million of credit financing for the
project. Our agreements impose restrictions on the sale and transfer of these
shares subject to disbursements under the credit financing and provide that for
every $2.5 million of credit made available, 1 percent of the interest will be
released from the restrictions.
As of December 31, 2000, we had provided $22.0 million of credit, all of which
had been applied to the release of restrictions on the shares. As a result, we
had earned the right to remove restrictions from shares representing an
approximate 9 percent equity interest. From 1998 through December 2000, we
separately purchased shares representing an additional 20 percent equity
interest not subject to any sale or transfer restrictions. Including the
additional purchased shares, as of December 31, 2000, we owned a total of 60
percent of the voting shares of Arctic Gas, of which 29 percent was not subject
to restrictions.
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The following table summarizes our ownership interests of Arctic Gas Company:
AS OF DECEMBER 31,
------------------
2000 1999
---- ----
Shares released from restrictions 9% 5%
Additional purchased shares 20% 19%
--------- ----------
Total shares not subject to restrictions 29% 24%
Shares subject to restrictions 31% 35%
--------- ----------
Total ownership 60% 59%
========= ==========
LOCATION AND GEOLOGY
The Samburg and Yevo-Yakha License Blocks comprise 794,972 acres and are
situated approximately 150 miles north of Geoilbent in the Yamal-Nenets
Autonomous Region of Russia. The towns and communities of Novy Urengoy, Samburg,
Urengoy and Nyda are located near the two licenses. Extensive exploration
drilling and testing (over 90 wells) on the Samburg and Yevo-Yakha licenses has
resulted in the discovery of major resources of natural gas, condensate and oil.
The primary reservoirs of these fields are currently being produced in both the
adjacent Urengoy Field and Rospan Block. Historic production at the Urengoy
Field is now on decline, and the undeveloped reserves discovered on the adjacent
Arctic Gas and Rospan Blocks may be of interest to Gazprom and Russia as
replacement for the production that is being lost at Urengoy.
DRILLING AND DEVELOPMENT ACTIVITY
Arctic Gas has reactivated six previously drilled oil wells through March 23,
2001. We are trucking oil to storage facilities where it is collected for sale.
Arctic Gas is currently producing approximately 2,300 Bbls of oil per day.
The following table sets forth reactivation activity and production information
for each of the quarters presented:
AVERAGE DAILY
WELLS REACTIVATED PRODUCTION FROM FIELD (Bbls)
----------------- ----------------------------
1999:
Fourth Quarter.................................... 1 -
2000:
First Quarter..................................... - 400
Second Quarter.................................... 2 940
Third Quarter..................................... 1 1,500
Fourth Quarter.................................... 1 1,700
Arctic Gas is currently planning for a Samburg oil and natural gas pilot
development project. The pilot project calls for:
- drilling new wells;
- installing natural gas processing facilities; and
- connecting into the export pipeline system.
The Arctic Gas blocks are located in the heart of the Urengoy/Yamburg producing
and support infrastructure region and are well situated for development. Natural
gas export trunklines are located 11 kilometers from the blocks. Arctic Gas and
Gazprom have entered into preliminary agreements to allow access to existing
oil, liquids and natural gas pipelines and facilities that could potentially
result in product sales to domestic and export markets. Arctic Gas is in
discussions with various parties concerning the export of natural gas, although
there are no assurances that contracts will result from these discussions.
Gazprom has granted Arctic Gas access to its transportation system beginning in
the third quarter of 2001 for natural gas sales from the blocks to certain
customers in the former Soviet Union.
Further development activities are subject to the pace and scope of Arctic Gas's
internally generated funds and to our ability to provide or arrange further
funding.
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EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS
Arctic Gas is a Russian company that employs Russian nationals almost
exclusively. Presently, there are two full-time expatriates working with Arctic
Gas and 111 local employees. We have conducted community relations programs in
Russia, providing medical care, training, equipment and supplies in towns in
which Arctic Gas personnel reside and also for the nomadic indigenous population
which reside in the area of oilfield operations.
WAB-21, SOUTH CHINA SEA (BENTON OFFSHORE CHINA COMPANY)
GENERAL
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, 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.
LOCATION AND GEOLOGY
The WAB-21 contract area is located approximately 50 miles southeast of the Dai
Hung (Big Bear) Oil Field. The block is adjacent to British Petroleum's giant
natural gas discovery at Lan Tay (Red Orchid) and 100 miles north of Exxon's
Natuna Discovery. The contract area covers several similar structural trends,
each with potential for hydrocarbon reserves in possible multiple pay zones.
The contract area is located northwest of Zengmu Basin (Offshore Sarawak), where
two Chinese institutions have already conducted geophysical seismic surveys.
Based on the multi-disciplinary data available from Zengmu Basin to the
southeast, East Natuna Basin to the south and southwest, and WAN'AN (Con Son)
Basin to the west and northwest, there is substantial evidence of hydrocarbon
potential in the contract area.
DRILLING AND DEVELOPMENT ACTIVITY
Due to the sovereignty issues, we have been unable to pursue an exploration
program during phase one of the contract. As a result, we have obtained
extensions, with the current extension in effect until June 2001. We expect
extensions to continue to be available to us. China and Vietnam are now engaged
in discussions to resolve the territorial dispute, although there is no
certainty of timing or the outcome of such discussions. Once there has been a
resolution of the disputes, an exploration program will commence including the
acquisition of 2-D seismic data as required by the petroleum contract with
CNOOC.
DOMESTIC OPERATIONS
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. We 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 1999, we drilled the 2199 #7 exploratory well to the Gaviota
anticline. Drill stem tests proved to be inconclusive or non-commercial, and we
temporarily abandoned the well for further evaluation. In November 1999, 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.
In April 2000, we entered into a retainer agreement, and in May 2000 an
exploration agreement, with Coastline Energy Corporation. The purpose of these
agreements was to acquire, explore and develop oil and natural gas prospects
both onshore and in the state waters of the
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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 on:
- oil and natural gas production acquired or developed; and
- 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 Bbls 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 cash and a 5 percent carried working interest in up to four
wells that may be drilled in the future.
RESERVES
Estimates of our proved reserves as of December 31, 2000 were prepared by Ryder
Scott Company, LP, independent petroleum engineers. In prior years, reserve
estimates were prepared by us and audited by Huddleston & Co., Inc., independent
petroleum engineers. The following table sets forth information regarding
estimates of proved reserves at December 31, 2000. The Venezuelan information
includes reserve information net of a 20 percent deduction for the minority
interest in Benton-Vinccler. All Venezuelan reserves are attributable to an
operating service agreement between Benton-Vinccler and PDVSA, under which all
mineral rights are owned by the Government of Venezuela. Although we estimate
that there are substantial natural gas reserves in the Benton-Vinccler
properties in Venezuela and the license blocks held by Geoilbent, no natural gas
reserves have been recorded as of December 31, 2000 because of a lack of sales
and/or transportation contracts in place. Natural gas proved reserves have been
recognized for Arctic Gas, which has transportation and marketing contracts in
place. Geoilbent and Benton-Vinccler are currently considering alternatives to
market the natural gas.
NET CRUDE OIL AND CONDENSATE (MBbls)
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
---------- ------------ --------
Venezuela ............................................. 53,774 44,657 98,431
Geoilbent ............................................. 14,913 17,702 32,615
Arctic Gas(1) ......................................... 2,325 13,495 15,820
-------- -------- --------
Total ......................................... 71,012 75,854 146,866
======== ======== ========
NET NATURAL GAS (MMcf)
----------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
---------- ----------- ------
Arctic Gas(1) 17,801 134,695 152,496
======== ======== ========
(1) Based on 29 percent ownership not subject to restrictions as of December
31, 2000.
Estimates of commercially recoverable oil and natural gas reserves and of the
future net cash flows derived therefrom are based upon a number of variable
factors and assumptions, such as:
- historical production from the subject properties;
- comparison with other producing properties;
- the assumed effects of regulation by governmental agencies; and
- assumptions concerning future operating costs, severance and excise
taxes, export tariffs, abandonment costs, development costs and
workover and remedial costs, all of which may vary considerably from
actual results.
All such estimates are to some degree speculative, and various classifications
of reserves are only attempts to define the degree of speculation involved. For
these reasons, estimates of the commercially recoverable reserves of oil
attributable to any particular property or group of properties, the
classification, cost and risk of recovering such reserves and estimates of the
future net cash flows expected therefrom, prepared by different engineers or by
the same engineers at different times may vary substantially. The difficulty of
making precise estimates is accentuated by the fact that 57 percent of our total
proved reserves were undeveloped as of December 31, 2000.
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Therefore, the following costs will likely vary from our estimates and such
variances may be material:
- actual production;
- oil sales;
- severance and excise taxes;,
- export tariffs;
- development expenditures;
- workover and remedial expenditures;
- abandonment expenditures; and
- operating expenditures.
Reserve estimates are not constrained by the availability of the capital
resources required to finance the estimated development and operating
expenditures.
In addition, actual future net cash flows will be affected by factors such as:
- actual production;
- supply and demand for oil;
- availability and capacity of gathering systems and pipelines;
- changes in governmental regulations or taxation; and
- the impact of inflation on costs.
The timing of actual future net oil sales from proved reserves, and thus their
actual present value, can be affected by the timing of the incurrence of
expenditures in connection with development of oil and gas properties. The 10
percent discount factor, which is required by the SEC to be used to calculate
present value for reporting purposes, is not necessarily the most appropriate
discount factor based on interest rates in effect from time to time and risks
associated with the oil and natural gas industry. Discounted present value, no
matter what discount rate is used, is materially affected by assumptions as to
the amount and timing of future production, which assumptions may and often do
prove to be inaccurate. For the period ending December 31, 2000, we reported
$583.1 million of discounted future net cash flows before income taxes from
proved reserves based on the SEC's required calculations.
PRODUCTION, PRICES AND LIFTING COST SUMMARY
In the following table we have set forth by country our net production, average
sales prices and average lifting costs for the years ended December 31, 2000,
1999 and 1998. The presentation for Venezuela includes 100 percent of the
production, without deduction for minority interest. Geoilbent (34 percent
ownership) and Arctic Gas (29 percent, 24 percent and 10 percent ownership not
subject to any sale or transfer restrictions at December 2000, 1999 and 1998,
respectively), which are accounted for under the equity method, have been
included at their respective ownership interest in the consolidated financial
statements based on a fiscal period ending September 30 and, accordingly, our
results of operations for the years ended December 31, 2000, 1999 and 1998
reflect results from Geoilbent for the twelve months ended September 30, 2000,
1999 and 1998, and from Arctic Gas for the twelve months ended September 30,
2000.
YEARS ENDED DECEMBER 31,
------------------------
2000 1999 1998
---- ---- ----
VENEZUELA
Net Crude Oil Production (Bbls)......... 9,364,088 9,666,958 12,172,352
Average Crude Oil Sales Price ($ per Bbl) $ 14.94 $9.21 $6.75
Average Lifting Costs ($ per Bbl)...... $ 5.01 $4.02 $3.21
GEOILBENT
Average Crude Oil Production (Bbls)..... 1,444,181 1,451,000 923,602
Average Crude Oil Sales Price ($ per Bbl) $ 17.45 $7.68 $8.72
Average Lifting Costs ($ per Bbl)...... $ 7.03 $3.41 $6.09
ARCTIC GAS
Net Crude Oil Production (Bbls)......... 48,833 - -
Average Crude Oil Sales Price ($ per Bbl) $ 18.20 - -
Average Lifting Costs ($ per Bbl)...... $ 12.99 - -
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REGULATION
GENERAL
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;
- limitations on oil and natural gas production;
- tax and other laws relating to the petroleum industry; o changes in
such laws; and
- changes in administrative regulations and the interpretation 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 costs. In any country in which
we may do business, the oil and natural gas industry legislation and agency
regulation is periodically changed for a variety of political, economic,
environmental and other reasons. Numerous governmental departments and agencies
issue rules and regulations binding on the oil and natural gas industry, some of
which carry substantial penalties for the failure to comply. The regulatory
burden on the oil and natural gas industry increases our cost of doing business.
VENEZUELA
Venezuela requires environmental and other permits for certain operations
conducted in oil field development, such as site construction, drilling, and
seismic activities. As a contractor to PDVSA, Benton-Vinccler submits capital
and operating budgets to PDVSA for approval. Capital expenditures to comply with
Venezuelan environmental regulations relating to the reinjection of natural gas
in the field and water disposal were $1.1 million in 2000 and are expected to be
$2.5 million in 2001. Benton-Vinccler also submits requests for permits for
drilling, seismic and operating activities to PDVSA, which then obtains such
permits from the Ministry of Energy and Mines and Ministry of Environment, as
required. Benton-Vinccler is also subject to income, municipal and value-added
taxes, and must file certain monthly and annual compliance reports to the
national tax administration and to various municipalities.
RUSSIA
Geoilbent and Arctic Gas submit annual production and development plans, which
include information necessary for permits and approvals for their planned
drilling, seismic and operating activities, to local and regional governments
and to the Ministry of Fuel and Energy and the Ministry of Natural Resources.
They also submit annual production targets and quarterly export nominations for
oil pipeline transportation capacity to the Ministry of Fuel and Energy.
Geoilbent and Arctic Gas are subject to customs, value-added, and municipal and
income taxes. Various municipalities and regional tax inspectorates are involved
in the assessment and collection of these taxes. Geoilbent and Arctic Gas must
file operating and financial compliance reports with several agencies, including
the Ministry of Fuel and Energy, Ministry of Natural Resources, Committee for
Technical Mining Monitoring and the State Customs Committee.
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 increased to 34 Euros per ton
(approximately $3.80 per barrel) on November 3, 2000 from 15 Euros per ton in
1999. We are unable to predict the impact of taxes, duties and other burdens in
the future for our Russian operations.
DRILLING, ACQUISITION AND FINDING COSTS
From commencement of operations through December 31, 2000, we added, net of
production and property sales, approximately 171.5 MMBOE of proved reserves
through purchases of reserves-in-place, discoveries of oil and natural gas
reserves, extensions of existing producing fields and revisions of previously
estimated reserves, for which the finding costs were $2.13 per BOE. Our estimate
of future development costs for our undeveloped proved reserves at December 31,
2000 was $1.90 per BOE. The estimated future development costs are based upon
our anticipated cost of developing our non-producing proved reserves, which
costs are calculated using historical costs for similar activities.
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For acquisitions of leases and producing properties, development and exploratory
drilling, production facilities and additional development activities such as
workovers and recompletions, we spent approximately (excluding our share of
capital expenditures incurred by equity affiliates):
- $ 50 million during 2000;
- $ 33 million during 1999; and
- $ 94 million during 1998.
We have drilled or participated in the drilling of wells as follows:
YEARS ENDED DECEMBER 31,
------------------------
2000 1999 1998
---- ---- ----
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
WELLS DRILLED:
Exploratory:
Crude oil................................. - - - - - -
Natural gas............................... - - - - - -
Dry holes................................. - - 3 1.60 - -
Development:
Crude oil................................. 65 34.06 28 9.18 46 22.54
Natural gas............................... - - - - - -
Dry holes................................. - - - - - -
------ --------- ------ -------- ------ -------
TOTAL................................ 65 34.06 31 10.78 46 22.54
====== ========= ====== ======== ====== =======
AVERAGE DEPTH OF WELLS (FEET).................. 7,048 9,092 7,934
PRODUCING WELLS(1):
Crude Oil................................. 268 163.55 181 108.00 159 97.30
Natural Gas............................... - - - - - -
(1) The information related to producing wells reflects wells we drilled, wells
we participated in drilling and producing wells we acquired.
At December 31, 2000, we were participating in the drilling of five wells in
Russia.
All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We do not own any drilling equipment.
ACREAGE
The following table summarizes the developed and undeveloped acreage that we
owned, leased or had under concession as of December 31, 2000:
DEVELOPED UNDEVELOPED
GROSS NET GROSS NET
Venezuela(1) ........................ 9,748 7,798 673,390 276,065
Russia(2) ........................... 41,936 13,965 2,109,879 677,109
China ............................... - - 7,470,080 7,470,080
United States ....................... - - 15,874 13,718
-------- -------- ---------- ---------
Total ...................... 51,684 21,763 10,269,223 8,436,972
======== ======== ========== =========
(1) Venezuela includes 525,295 gross acres related to our Delta Centro
project, which was in the process of being abandoned at December 31,
2000.
(2) Russia includes 794,972 gross acres related to Arctic Gas, which is
included based on a 29 percent ownership interest.
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COMPETITION
We encounter strong competition from major oil and gas companies and independent
operators in acquiring properties and leases for exploration for crude oil and
natural gas. The principal competitive factors in the acquisition of such oil
and gas properties include the staff and data necessary to identify, investigate
and purchase such leases, and the financial resources necessary to acquire and
develop such leases. Many of our competitors have financial resources, staffs
and facilities substantially greater than ours.
EMPLOYEES AND CONSULTANTS
At December 31, 2000, we had 52 full-time employees, augmented from time-to-time
with independent consultants, as required. Benton-Vinccler had 160 employees,
Geoilbent had 603 employees and Arctic Gas had 111 employees.
TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE
All Venezuelan reserves are attributable to an operating service agreement
between Benton-Vinccler and PDVSA, under which all mineral rights are owned by
the Government of Venezuela. With regard to Russian acreage, Geoilbent and
Arctic Gas have obtained certain documentation from appropriate regulatory
agencies in Russia which we believe is adequate to establish their right to
develop, produce and market oil and natural gas from their fields.
The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea,
with an option for another 1.0 million acres under certain circumstances, and
lies within an area which is the subject of a territorial dispute between the
People's Republic of China and Vietnam. Vietnam has executed an agreement on a
portion of the same offshore acreage with Conoco Inc. The territorial dispute
has existed for many years, and there has been limited exploration and no
development activity in the area under dispute. It is uncertain when or how this
dispute will be resolved, and under what terms the various countries and parties
to the agreements may participate in the resolution, although certain proposed
economic solutions currently under discussion would result in our interest being
reduced.
As is customary in the oil and natural gas industry, we make a limited review of
title to farmout acreage and to undeveloped U.S. oil and natural gas leases upon
execution of the contracts and leases. Prior to the commencement of drilling
operations, a thorough drillsite title examination is conducted and curative
work is performed with respect to significant defects. We follow the practice of
obtaining title opinions on our domestic producing properties and believe that
we have satisfactory title to such properties in accordance with standards
generally accepted in the oil and natural gas industry. Our oil and natural gas
properties are subject to customary royalty interests, liens for current taxes,
and other burdens which we believe do not materially interfere with the use of
or affect the value of such properties.
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GLOSSARY
When the following terms are used in the text they have the meanings indicated.
MCF. "Mcf" means thousand cubic feet. "Mmcf" means million cubic feet.
"Bcf" means billion cubic feet. "Tcf" means trillion cubic feet.
BBL. "Bbl" means barrel. "Bbls" means barrels. "MBbls" means thousand
barrels. "MMBbls" means million barrels. "BBbls" means billion barrels.
BOE. "BOE" means barrels of oil equivalent, which are determined using the
ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf
of natural gas so that six Mcf of natural gas is referred to as one barrel of
oil equivalent or "BOE". "MBOE" means thousands of barrels of oil equivalent.
"MMBOE" means millions of barrels of oil equivalent.
CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with
exploratory and development drilling (including exploratory dry holes);
leasehold acquisitions; seismic data acquisitions; geological, geophysical and
land-related overhead expenditures; delay rentals; producing property
acquisitions; and other miscellaneous capital expenditures.
COMPLETION COSTS. "Completion Costs" means, as to any well, all those
costs incurred after the decision to complete the well as a producing well.
Generally, these costs include all costs, liabilities and expenses, whether
tangible or intangible, necessary to complete a well and bring it into
production, including installation of service equipment, tanks, and other
materials necessary to enable the well to deliver production.
DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional
well to the same reservoir as other producing wells on a lease, or drilled on an
offset lease not more than one location away from a well producing from the same
reservoir.
EXPLORATORY WELL. An "Exploratory Well" is a well drilled in search of a
new and as yet undiscovered pool of oil or natural gas, or to extend the known
limits of a field under development.
FINDING COST. "Finding Cost", expressed in dollars per BOE, is calculated
by dividing the amount of total capital expenditures related to acquisitions,
exploration and development costs (reduced by proceeds for any sale of oil and
gas properties) by the amount of total net reserves added or reduced as a result
of property acquisitions and sales, drilling activities and reserve revisions
during the same period.
FUTURE DEVELOPMENT COST. "Future Development Cost" of proved nonproducing
reserves, expressed in dollars per BOE, is calculated by dividing the amount of
future capital expenditures related to development properties by the amount of
total proved non-producing reserves associated with such activities.
GROSS ACRES OR WELLS. "Gross Acres or Wells" are the total acres or wells,
as the case may be, in which an entity has an interest, either directly or
through an affiliate.
LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a
producing formation to the surface, consisting of the costs incurred to operate
and maintain wells and related equipment and facilities, including labor costs,
repair and maintenance, supplies, insurance, production, severance and windfall
profit taxes.
NET ACRES OR WELLS. A party's "Net Acres" or "Net Wells" are calculated by
multiplying the number of gross acres of gross wells in which that party has an
interest by the fractional interest of the party in each such acre or well.
PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved
Developed Reserves expected to be produced from existing completion intervals
now open for production in existing wells. "Producing Properties" are properties
to which Producing Reserves have been assigned by an independent petroleum
engineer.
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PROVED DEVELOPED RESERVES. "Proved Developed Reserves" are Proved Reserves
which can be expected to be recovered through existing wells with existing
equipment and operating methods.
PROVED RESERVES. "Proved Reserves" are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known oil and natural gas reservoirs under existing economic and operating
conditions, that is, on the basis of prices and costs as of the date the
estimate is made and any price changes provided for by existing conditions.
PROVED UNDEVELOPED RESERVES. "Proved Undeveloped Reserves" are Proved
Reserves which can be expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion.
RESERVES. "Reserves" means crude oil and natural gas, condensate and
natural gas liquids, which are net of leasehold burdens, are stated on a net
revenue interest basis, and are found to be commercially recoverable.
ROYALTY INTEREST. A "Royalty Interest" is an interest in an oil and gas
property entitling the owner to a share of oil and natural gas production (or
the proceeds of the sale thereof) free of the costs of production.
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS. The "Standardized Measure
of Future Net Cash Flows" is a method of determining the present value of Proved
Reserves. The future net oil sales from Proved Reserves are estimated assuming
that oil and natural gas prices and production costs remain constant. The
resulting stream of oil sales is then discounted at the rate of 10 percent per
year to obtain a present value.
3-D SEISMIC. "3-D Seismic" is the method by which a continuous three
dimensional image of the earth's subsurface is created through the
interpretation of seismic data. 3-D surveys allow for a more detailed
understanding of the subsurface than do conventional surveys and contribute
significantly to field appraisal, development and production.
2-D SEISMIC. " 2-D Seismic" is the method by which discreet
two-dimensional profiles of the earth's subsurface are interpreted and
interpolated to provide a basic understanding of the subsurface.
UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and natural gas acreage
on which wells have not been drilled or completed to a point that would permit
commercial production regardless of whether such acres contain proved reserves.
ITEM 2. PROPERTIES
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 separate building
for approximately $76,000 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 $50,000 per month.
ITEM 3. LEGAL PROCEEDINGS
On February 17, 1998, the WRT Creditors Liquidation 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.
The suit seeks a determination that the sale by BOGLA to Tesla Resources
Corporation, a wholly owned subsidiary of WRT Energy Corporation, of certain
West Cote Blanche Bay properties for $15.1 million, constituted a fraudulent
conveyance under 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
have been filed. We believe that this case lacks merit and that an unfavorable
outcome is unlikely.
In 1996, 1997 and November 1998, we made certain 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. At
December 31, 1997, the aggregate outstanding amounts of the loans were $2.0
million. At September 30, 1998, the aggregate outstanding amounts of the loans
were $4.4 million. In the fourth quarter of 1998,we loaned Mr. Benton an
additional $1.1 million. The proceeds of the loan were to be used to pay in full
certain margin account obligations owed to third parties which had obtained a
pledge from Mr. Benton of his shares of Benton stock. We then obtained a
security interest in those shares of stock, certain personal real estate and
proceeds from certain contractual and stock option agreements. At December 31,
1998, the $5.5 million owed to us by Mr. Benton exceeded the value of our
collateral, due to
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the decline in the price of Benton stock. As a result, we
recorded an allowance for doubtful accounts of $2.9 million. The portion of the
note secured by Benton stock and stock options, $2.1 million, was presented
on our balance sheet as a reduction from stockholders' equity at December 31,
1998. In August 1999, Mr. Benton filed a Chapter 11 (reoganization) 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.
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 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 first half of 2001, we will retain
our security interest in Mr. Benton's 600,000 shares of Benton stock and in his
stock options, and in a portion of certain proceeds of his Consulting Agreement.
Repayment of any amounts of these loans by Mr. Benton will be achieved through
Mr. Benton's liquidation of certain real and personal property assets; a phased
liquidation of Benton stock resulting from Mr. Benton's exercise of his Benton
stock options; and, if necessary, from the retained interest in the portion of
the Consulting Agreement's proceeds. The amount we eventually realize and the
timing of our receipt of payments will depend upon the timing and results of the
liquidation of Mr. Benton's assets, including Benton Oil and Gas Company stock.
In the normal course of our business, there are various other legal proceedings
outstanding. In the opinion of management, these proceedings will not have a
material adverse effect on our financial position, results of operations or
liquidity.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the three month period ended December 31, 2000, no matter was submitted
to a vote of security holders.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our Common Stock has traded on the New York Stock Exchange ("NYSE") since April
29, 1997 under the symbol "BNO." As of December 31, 2000, there were 33,821,919
shares of Common Stock outstanding held of record by approximately 962
stockholders. The following table sets forth the high and low sales prices for
our Common Stock reported by the NYSE.
YEAR QUARTER HIGH LOW
- -------------- -------------------------- ------------ ------------
1999
First quarter $5.19 $1.94
Second quarter 4.38 1.88
Third quarter 3.13 1.50
Fourth quarter 2.75 1.44
2000
First quarter 4.50 1.56
Second quarter 3.56 2.00
Third quarter 3.19 1.94
Fourth quarter 2.75 1.38
On March 28, 2001, the last sales price for the Common Stock as reported by NYSE
was $2.00 per share.
Our policy is to retain earnings to support the growth of our business.
Accordingly, our Board of Directors has never declared cash dividends on our
Common Stock, and our indentures currently restrict the declaration and payment
of any cash dividends.
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ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth our selected consolidated financial data for each
of the years in the five year period ended December 31, 2000. The selected
consolidated financial data have been derived from, and should be read in
conjunction with our annual audited consolidated financial statements, including
the notes thereto. Our year end financial information contains results from our
Russian operations based on a twelve month period ending September 30.
Accordingly, our results of operations for the years ended December 31, 2000,
1999 and 1998 reflect results from Geoilbent for the twelve months ended
September 30, 2000, 1999 and 1998, and from Arctic Gas for the twelve months
ended September 30, 2000 and 1999.
YEARS ENDED DECEMBER 31,
------------------------
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENTS OF OPERATIONS:
Total revenues ..................................................... $ 140,284 $ 89,060 $ 82,212 $ 154,033 $ 138,656
Operating expenses ................................................. 47,430 39,393 40,066 35,184 18,069
Depletion, depreciation and amortization ........................... 17,175 16,519 33,157 44,513 31,778
Write-downs of oil and gas properties
and impairments ................................................ 1,346 25,891 193,893 - -
General and administrative expenses ................................ 16,739 25,969 21,485 17,676 15,139
Taxes other than on income ......................................... 4,390 3,813 3,677 5,361 3,130
--------- --------- --------- --------- ---------
Operating income (loss) ............................................ 53,204 (22,525) (210,066) 51,299 70,540
Investment income and other ........................................ 8,559 8,986 13,982 12,594 7,281
Interest expense ................................................... (28,973) (29,247) (32,007) (24,082) (15,578)
Net gain on exchange rates ......................................... 326 1,044 1,767 2,011 1,831
Partnership exchange expenses ...................................... - - - - (2,140)
Gain on sale of properties ......................................... - - - - 7,175
--------- --------- --------- --------- ---------
Income (loss) from consolidated companies before
income taxes and minority interests ............................ 33,116 (41,742) (226,324) 41,822 69,109
Income tax expense (benefit) ....................................... 14,032 (7,526) (24,911) 16,620 19,922
--------- --------- --------- --------- ---------
Income (loss) before minority interests ............................ 19,084 (34,216) (201,413) 25,202 49,187
Minority interest in consolidated subsidiary
Companies ...................................................... 7,869 937 (22,895) 6,333 9,984
--------- --------- --------- --------- ---------
Income (loss) from consolidated companies .......................... 11,215 (35,153) (178,518) 18,869 39,203
Equity in net earnings (losses) of affiliate companies (2) ......... 5,313 2,869 (5,062) (820) (846)
--------- --------- --------- --------- ---------
Income (loss) before extraordinary items ........................... 16,528 (32,284) (183,580) 18,049 38,357
Extraordinary income (expense) ..................................... 3,960 - - - (10,075)
--------- --------- --------- --------- ---------
Net income (loss) .................................................. $ 20,488 $ (32,284) $(183,580) $ 18,049 $ 28,282
========= ========= ========= ========= =========
Net income (loss) per common share :
Basic:
Income (loss) before extraordinary items .................... $ 0.54 ($ 1.09) ($ 6.21) $ 0.62 $ 1.42
Extraordinary items ......................................... 0.13 - - - (0.38)
--------- --------- --------- --------- ---------
Net income (loss) ........................................... $ 0.67 ($ 1.09) ($ 6.21) $ 0.62 $ 1.04
========= ========= ========= ========= =========
Diluted:
Income (loss) before extraordinary items .................... $ 0.53 ($ 1.09) ($ 6.21) $ 0.59 $ 1.29
Extraordinary items ......................................... 0.13 - - - (0.34)
--------- --------- --------- --------- ---------
Net income (loss) ........................................... $ 0.66 ($ 1.09) ($ 6.21) $ 0.59 $ 0.95
========= ========= ========= ========= =========
Weighted average common shares outstanding
Basic .......................................................... 30,724 29,577 29,554 29,119 27,088
Diluted ........................................................ 30,890 29,577 29,554 30,834 29,813
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AT DECEMBER 31,
---------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
BALANCE SHEET DATA:
Working capital ................................... $ 12,370 $ 32,093 $ 60,927 $174,759 $106,051
Total assets ...................................... 286,447 276,311 324,363 573,599 425,810
Long-term obligations, net of current position .... 213,000 264,575 280,002 280,016 175,028
Stockholders' equity (deficit)(1) ................. 12,904 (17,178) 12,989 197,732 174,899
(1) No cash dividends were paid during the periods presented.
(2) As discussed in Note 1 to the Financial Statements, in 1999 we changed our
method of reporting our investment in Geoilbent.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS
As a result of our increased leverage and poor investment returns since 1998,
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 aimed at creating new
stockholder value, we undertook several significant actions beginning in 2000,
including:
- Hired a new President and Chief Executive Officer, a new Senior
Vice President and Chief Financial Officer and a new Vice
President and General Counsel;
- Reconstituted our Board of Directors with industry executives
with proven experience in oil and natural gas operations,
finance and international operations;
- Redefined our strategic priorities to focus on value creation;
- Initiated capital conservation steps and financial transactions
to de-leverage the company and improve cash flow for
reinvestment;
- Undertook a comprehensive study of our core Venezuelan asset to
attempt to enhance the value of its production, thus ultimately
increasing cash flow and potentially extending its productive
life.
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. 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 advisors, are
conducting a comprehensive review of strategic alternatives, including, but not
limited to, selling all or part of our existing assets in Venezuela and Russia,
debt restructuring, some combination thereof, 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.
Our results of operations reflect the results of Geoilbent for the twelve months
ended September 30, 2000, 1999 and 1998, and the results of Arctic Gas for the
twelve months ended September 30, 2000 and 1999.
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 each
of the years in the three year period ended December 31, 2000 and the financial
condition as of December 31, 2000 and 1999 in conjunction with our Consolidated
Financial Statements and related Notes thereto.
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We have presented selected expense items from our consolidated income statement
as a percentage of oil and natural gas sales in the following table:
YEARS ENDED DECEMBER 31,
------------------------
2000 1999 1998
---- ---- ----
Operating Expenses................................... 34% 44% 49%
Depletion, Depreciation and Amortization............. 12 19 40
General and Administrative........................... 12 29 26
Taxes Other Than on Income........................... 3 4 4
Interest............................................. 21 33 39
YEARS ENDED DECEMBER 31, 2000 AND 1999
Our results of operations for the year ended December 31, 2000 primarily
reflected the results for Benton-Vinccler, C.A. in Venezuela, which accounted
for substantially all of our production and oil sales revenue. As a result of
increases in world crude oil prices, partially offset by lower production from
the South Monagas Unit, oil sales in Venezuela were 57 percent higher in 2000
compared with 1999. Realized fees per barrel increased 62 percent (from $9.21 in
1999 to $14.94 in 2000) and oil sales quantities decreased 3 percent (from 9.7
MMBbls of oil in 1999 to 9.4 MMBbls of oil in 2000). Our operating expenses from
the South Monagas Unit increased 21 percent primarily due to increased chemical
treatment, electricity and natural gas compression station maintenance and
operating costs, partially offset by reduced salaries and material costs.
We had revenues of $140.3 million for the year ended December 31, 2000. The
expenses we incurred during the period consisted of:
- operating expenses of $47.4 million;
- depletion, depreciation and amortization expense of $17.2
million;
- write-downs of oil and gas properties and impairments of $1.3
million;
- general and administrative expense of $16.7 million;
- taxes other than on income of $4.4 million;
- interest expense of $29.0 million;
- income tax expense of $14.0 million; and
- minority interest of $7.9 million.
Other items of income consisted of:
- investment income and other of $8.6 million;
- net gain on exchange rates of $0.3 million;
- equity in net earnings of affiliated companies of $5.3 million;
and
- extraordinary gain on the repurchase of long-term notes of $4.0
million.
Our net income was $20.5 million or $0.66 per share (diluted).
By comparison, we had revenues of $89.1 million for the year ended December 31,
1999. The expenses we incurred during the period consisted of:
- operating expenses of $39.4 million;
- depletion, depreciation and amortization expense of $16.5
million;
- write-downs of oil and gas properties and impairments of $25.9
million;
- general and administrative expense of $26.0 million;
- taxes other than on income of $3.8 million;
- interest expense of $29.2 million;
- income tax benefit of $7.5 million; and
- minority interest of $0.9 million.
Other items of income consisted of:
- investment income and other of $9.0 million;
- net gain on exchange rates of $1.0 million; and
- equity in net earnings of affiliated companies of $2.9 million.
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Our net loss was $32.3 million or $1.09 per share (diluted).
Our revenues increased $51.2 million, or 57 percent, during the year ended
December 31, 2000 compared with 1999. This was due to increased oil sales
revenue in Venezuela as a result of increases in world crude oil prices,
partially offset by lower sales quantities. Our sales quantities for the year
ended December 31, 2000 from Venezuela were 9.4 MMBbls compared to 9.7 MMBbls
for the year ended December 31, 1999. The decrease in sales quantities of
302,890 Bbls, or 3 percent, was due primarily to production declines beginning
in 1999 resulting from the curtailment of the Venezuelan development drilling
program. Venezuelan production declined to 24,300 Bbls of oil per day by the end
of 1999. Production increased to 28,000 Bbls or oil per day by the end of 2000
as a result of drilling 26 additional wells during the year. Prices for crude
oil averaged $14.94 per Bbl (pursuant to terms of an operating service
agreement) from Venezuela compared with $9.21 per Bbl for 1999.
Our operating expenses increased $8.0 million, or 20 percent, during the year
ended December 31, 2000 compared to the year ended December 31, 1999. This was
primarily due to increased chemical treatment, electricity and natural gas
compression station maintenance and operating costs, which were partially offset
by reduced salaries and material costs at the South Monagas Unit in Venezuela.
Depletion, depreciation and amortization increased $0.7 million, or 4 percent,
during the year ended December 31, 2000 compared with 1999 primarily due to
decreased proved reserves and increased future development costs at the South
Monagas Unit. Depletion expense per barrel of oil produced from Venezuela during
2000 was $1.68 compared with $1.53 during 1999. We recognized write-downs of
capitalized costs of $1.3 million associated with exploration activities in
Jordan and California during the year ended December 31, 2000 compared with
$25.9 million associated with exploration activities in California, China,
Senegal and Jordan during the year ended December 31, 1999. General and
administrative expenses decreased $9.3 million, or 36 percent, during the year
ended December 31, 2000 compared with 1999. This was primarily due to the
following:
- our reduction in workforce and related restructuring costs in
1999;
- the write-off of the joint interest receivable due from Molino
Energy at December 31, 1999 associated with the California
Leases; and
- an allowance for doubtful accounts in 1999, related to amounts
owed to us by our former Chief Executive Officer (see Note 14 of
Notes to the Consolidated Financial Statements).
Taxes other than on income increased $0.6 million, or 16 percent, during the
year ended December 31, 2000 compared with 1999. This was primarily due to
increased Venezuelan municipal taxes, which are a function of oil revenues.
Investment income and other decreased $0.4 million, or 4 percent, during the
year ended December 31, 2000 compared with 1999. This was due to lower average
cash and marketable securities balances. Interest expense decreased $0.2
million, or 1 percent, during the year ended December 31, 2000 compared with
1999. This was primarily due to the reduction of debt balances, partially offset
by a reduction of capitalized interest expense. Net gain on exchange rates
decreased $0.7 million, or 70 percent for the year ended December 31, 2000
compared with 1999. This was due to changes in the value of the Bolivar. We
realized income before income taxes and minority interest of $33.1 million
during the year ended December 31, 2000 compared with a loss of $41.7 million in
1999. This resulted in increased income tax expense of $21.5 million. The
effective tax rate of 42 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 increased
$7.0 million for the year ended December 31, 2000 compared to 1999. This was
primarily due to the increased profitability of Benton-Vinccler.
Equity in net earnings of affiliated companies increased $2.4 million, or 83
percent, during the year ended December 31, 2000 compared with 1999. This was
primarily due to the increased income from Geoilbent. Our share of revenues from
Geoilbent was $25.2 million for the year ended September 30, 2000 compared with
revenues of $11.1 million for 1999. The increase of $14.1 million, or 127
percent, was due to significantly higher world crude oil prices partially offset
by lower sales quantities. Prices for Geoilbent's crude oil averaged $17.45 per
Bbl during the year ended September 30, 2000 compared with $7.68 per Bbl for the
year ended September 30, 1999. Our share of Geoilbent oil sales quantities
decreased by 6,819 Bbls, or 0.5 percent, from 1,451,000 BBls sold during the
year ended September 30, 1999 to 1,444,181 Bbls sold during the year ended
September 30, 2000. The decrease in oil sales was due primarily to the temporary
interruption of production in early 2000 resulting from an accident during the
period that affected certain production facilities. We recorded extraordinary
income of $4.0 million during the year ended December 31, 2000 related to the
repurchase at a discount of $17 million of our senior unsecured notes due in
2003. We exchanged a total of 4.2 million shares of our common stock with a
market value of $9.3 million and cash of $3.5 million for $17 million in notes.
We also wrote-off $0.2 million in unamortized loan fees related to the notes.
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CAPITAL RESOURCES AND LIQUIDITY
The oil and natural gas industry is a highly capital intensive and cyclical
business with unique operating and financial risks (see Risk Factors). 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.
Working Capital. Our capital resources and liquidity are affected by the timing
of our semiannual interest payments of approximately $11.4 million each May 1
and November 1 and by the quarterly payments from PDVSA at the end of the months
of February, May, August and November pursuant to the terms of the contract
between Benton-Vinccler and PDVSA regarding the South Monagas Unit. As a
consequence of the timing of these interest payment outflows and the PDVSA
payment inflows, 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. The
current interest rate on the facility is 16.5 percent. We borrowed 5 billion
Bolivars (approximately $7.2 million) in October under this facility, which we
repaid in November 2000. In December, we borrowed another 4 billion Bolivars
(approximately $5.7 million) at an interest rate of 12.5 percent, which we
repaid in January 2001. We believe that similar arrangements will be available
to us in future quarters.
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 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 above alternatives, or some
combination thereof, will be available or, if available, will be on terms
acceptable to us.
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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:
YEAR ENDED DECEMBER 31,
-----------------------
2000 1999 1998
-------------- ---------- ---------
Net cash provided by (used in) operating activities ................. $ 51,763 $ (1,392) $ 2,156
Net cash provided by (used in) investing activities ................. (28,772) 20,989 4,134
Net cash used in financing activities ............................... (29,006) (15,648) (823)
-------- -------- -------
Net increase (decrease) in cash ..................................... $ (6,015) $ 3,949 $ 5,467
======== ======== =======
At December 31, 2000, we had current assets of $63.6 million and current
liabilities of $51.3 million, resulting in working capital of $12.3 million and
a current ratio of 1.24:1. This compares with our working capital of $32.1
million and a current ratio of 2.17:1 at December 31, 1999. The decrease in
working capital of $19.8 million was primarily due to capital expenditures at
the South Monagas Unit in Venezuela and additional investments in and advances
to Arctic Gas Company during the year ended December 31, 2000.
Cash Flow from Operating Activities. During the year ended December 31, 2000 and
1999, net cash provided by (used in) operating activities was approximately
$51.8 million and $(1.4) million, respectively. Cash flow from operating
activities increased by $53.2 million during the year ended December 31, 2000
compared with 1999. This was primarily due to increased collections of accrued
oil revenues, increased accounts payable and accrued expenses associated with
the alliance agreements with Schlumberger and Helmerich & Payne and reduced
general and administrative expenses, which were partially offset by increases in
operating expenses, income taxes and taxes other than on income. Collections of
accrued oil revenues increased $51.4 million, and accounts payable and accrued
expenses increased $22.6 million during the year ended December 31, 2000
compared with 1999.
Cash Flow from Investing Activities. During the year ended December 31, 2000 and
1999, we had drilling and production related capital expenditures of
approximately $57.2 million and $37.0 million, respectively. Of the 2000
expenditures:
- $53.9 million was attributable to the development of the South
Monagas Unit in Venezuela;
- $ 0.2 million was related to costs on the Delta Centro Block in
Venezuela;
- $ 1.0 million was related to the Sirhan Block in Jordan;
- $ 1.1 million was attributable to the Gulf Coast; and
- $ 1.0 million was attributable to other projects.
In addition, during the year ended December 31, 2000, we increased our
investment in Arctic Gas by $10.8 million.
In August 1999, Benton-Vinccler sold its power generation facility located in
the Uracoa Field of the South Monagas Unit in Venezuela for $15.1 million.
Concurrent with the sale, Benton-Vinccler entered into a long-term power
purchase agreement with the purchaser of the facility to provide for the
electrical needs of the field throughout the remaining term of the operating
service agreement. Benton-Vinccler used the proceeds from the sale to repay
indebtedness that was collateralized by our time deposit. Permanent repayment of
a portion of the loan allowed us to reduce the cash collateral for the loan
thereby making such cash available for working capital needs.
As a result of the decline in oil prices, 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 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, we
suspended the development drilling program in Venezuela for a period of
approximately six months starting in January 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 known 123 MMBbls (98 MMBbls net to Benton) of proved
reserves of oil in the fields. Our goal will be an accelerated development
program with lower cost production, starting from the second half of 2001,
rising to an expected level of up to between 31,000-33,000 Bbls of oil
equivalent per day in less than two years. This is based on current internal
operating and financial assumptions and also assumes that we do not enter into a
transaction under which we sell a significant portion of our assets, as
described in "Item 1. Business - Management, Operational and Financial
Restrictions."
In the first half of 2001, we will concentrate on improving the production from
the existing 143 available wells in Venezuela. Production, currently (as of
March 23, 2001) at 28,500 Bbls of oil per day in Venezuela, is expected to
decline to between 25,000 and 26,000 Bbls of oil per day by mid-year, then
increase when the new development plan starts in the third quarter.
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We expect capital expenditures of approximately $44.2 million during the next 12
months, including $32.9 million at the South Monagas Unit and $7.7 million at
Delta Centro relating to the unused portion of the standby letter of credit that
was paid in January 2001 to terminate the contract. We also expect to increase
our investment in Arctic Gas by $5.0 million during the same period. 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 $22 million under this agreement. We
continue to evaluate funding alternatives for the loans to Arctic Gas. The
timing and size of the investments for the South Monagas Unit and Arctic Gas are
substantially at 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 under the alliance agreements with
Schlumberger and Helmerich & Payne indicate that the reservoir formation quality
is as expected, but may be sensitive to drilling and completion practices.
Additionally, a number of previously producing wells went off production during
2000, requiring maintenance operations. We are working with our alliance
partners on techniques to optimize the production from new wells and believe
that we can achieve improvements in production performance from the Uracoa
Field.
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 1st and November 1st of each year. The indenture agreements
provide for certain limitations on liens, additional indebtedness, certain
investment and capital expenditures, dividends, mergers and sales of assets. At
December 31, 2000, we were in compliance with all covenants of the indentures.
CONCLUSION
While we can give you no assurance, we currently believe that our capital
resources and liquidity will be adequate to fund our planned capital
expenditures, investments in and advances to affiliates, and semiannual interest
payment obligations for the next 12 months. Our 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 is a significant decrease in either price or
production levels related to the South Monagas Unit. Future cash flows are
subject to a number of variables including, but not limited to, the level of
production and prices, as well as various economic conditions that have
historically affected the oil and 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.
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.
RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1999 AND 1998
We had revenues of $89.1 million for the year ended December 31, 1999. The
expenses we incurred during the period consisted of:
- operating expenses of $39.4 million;
- depletion, depreciation and amortization expense of $16.5
million;
- write-downs of oil and gas properties and impairments of $25.9
million;
- general and administrative expense of $26.0 million;
- taxes other than on income of $3.8 million;
- interest expense of $29.2 million;
- income tax benefit of $7.5 million; and
- minority interest of $0.9 million.
Other items of income consisted of:
- investment income and other of $9.0 million;
- net gain on exchange rates of $1.0 million; and
- equity in net earnings of affiliated companies of $2.9 million.
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Our net loss was $32.3 million or $1.09 per share (diluted).
By comparison, we had revenues of $82.2 million for the year ended December 31,
1998. The expenses we incurred during the period consisted of:
- operating expenses of $40.1 million;
- depletion, depreciation and amortization expense of $33.2
million;
- write-downs of oil and gas properties and impairments of $193.9
million;
- general and administrative expense of $21.5 million;
- taxes other than on income of $3.7 million;
- interest expense of $32.0 million;
- income tax benefit of $24.9 million; and
- minority interest reduction of $22.9 million.
Other items of income consisted of:
- investment income and other of $14.0 million;
- net gain on exchange rates of $1.8 million; and
- equity in net losses of affiliated companies of $5.1 million.
Our net loss was $183.6 million or $6.21 per share (diluted).
Revenues increased $6.9 million, or 8 percent, during the year ended December
31, 1999 compared with 1998. This was due to increased oil sales revenue in
Venezuela as a result of increases in world crude oil prices substantially
offset by a 21 percent decrease in oil sales quantities. Sales quantities for
the year ended December 31, 1999 from Venezuela were 9.7 MMBbls compared with
12.2 MMBbls for the year ended December 31, 1998. The decrease in sales
quantities of 2.5 MMBbls was primarily due to the curtailment in 1998 and 1999
of the Venezuelan development drilling program. Prices for crude oil averaged
$9.21 per Bbl (pursuant to terms of an operating service agreement) from
Venezuela for the year ended December 31, 1999 compared with $6.75 per Bbl for
the year ended December 31, 1998.
Our operating expenses decreased $0.7 million, or 2 percent, during the year
ended December 31, 1999 compared with 1998. This was primarily due to a
stabilization of operating expenses in Venezuela. Depletion, depreciation and
amortization decreased $16.7 million, or 50 percent, during the year ended
December 31, 1999 compared with 1998. This was primarily due to write-downs of
oil and natural gas properties in Venezuela in 1998. Depletion expense per
barrel of oil produced from Venezuela during the year ended December 31, 1999
was $1.53 compared with $2.62 during1998. Additionally, we recognized
write-downs of capitalized costs of $25.9 million in 1999 associated with
exploration activities in California, China, Senegal and Jordan. General and
administrative expenses increased $4.5 million, or 21 percent, during the year
ended December 31, 1999 compared with 1998. This was primarily due to:
- our reduction in workforce and related restructuring costs;
- increasing consulting and legal fees;
- the write-off of the joint interest receivable due from Molino
Energy at December 31, 1999 associated with the California
Leases; and
- an allowance for doubtful accounts related to amounts owed to us
by our former Chief Executive Officer (see Note 14 of Notes to
the Consolidated Financial Statements).
Investment income and other decreased $5.0 million, or 36 percent, during the
year ended December 31, 1999 compared with 1998 due to lower average cash and
marketable securities balances. Interest expense decreased $2.8 million, or 9
percent, during the year ended December 31, 1999 compared with 1998 primarily
due to capitalized interest. Net gain on exchange rates decreased $0.8 million,
or 44 percent for the year ended December 31, 1999 compared with 1998 due to
changes in the value of the Bolivar. We realized a loss before income taxes and
minority interest of $41.7 million during the year ended December 31, 1999
compared with a loss of $226.3 million in 1998, which resulted in a decrease in
income tax benefit of $17.4 million or 70 percent primarily due to increased
taxable income in Venezuela. The net income attributable to the minority
interest increased $23.8 million, or 104 percent for 1999 compared with 1998.
This was primarily due to the increased profitability of Benton-Vinccler's
operations in Venezuela.
Equity in net earnings of affiliated companies were $2.9 million for the year
ended December 31, 1999 compared with equity in net losses of affiliated
companies of $5.1 million in 1998. The increase of $8.0 million was primarily
due to the increased income from Geoilbent. Our share of revenues from Geoilbent
was $11.1 million for the year ended September 30, 1999 compared with revenues
of $8.1 million for the year ended September 30, 1998. The increase of $3.0
million, or 37 percent, was due to significantly higher sales quantities, which
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were partially offset by lower average oil prices. Prices for Geoilbent's crude
oil averaged $7.68 per Bbl during the year ended September 30, 1999 compared
with $8.72 per Bbl for the year ended September 30, 1998. Our share of Geoilbent
oil sales quantities increased by 527,398 Bbls, or 57 percent, from 923,602 Bbls
sold during the year ended September 30, 1998 to 1,451,000 Bbls sold during the
year ended September 30, 1999. The increase in oil sales was primarily due to
the development of the North Gubkinskoye Field in Western Siberia region of
Russia.
RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1998 AND 1997
We had revenues of $82.2 million for the year ended December 31, 1998. Expenses
incurred during the period consisted of:
- operating expenses of $40.1 million;
- depletion, depreciation and amortization expense of $33.2
million;
- write-downs of oil and gas properties and impairments of $193.9
million;
- general and administrative expense of $21.5 million;
- taxes other than on income of $3.7 million;
- interest expense of $32.0 million;
- income tax benefit of $24.9 million; and
- minority interest reduction of $22.9 million.
Other items of income consisted of:
- investment income and other of $14.0 million;
- net gain on exchange rates of $1.8 million; and
- equity in net losses of affiliated companies of $5.1 million.
Our net loss was $183.6 million or $6.21 per share (diluted).
By comparison, we had revenues of $154.0 million for the year ended December 31,
1997. Expenses incurred during the period consisted of:
- operating expenses of $35.2 million;
- depletion, depreciation and amortization expense of $44.5
million;
- general and administrative expense of $17.7 million;
- taxes other than on income of $5.4 million;
- interest expense of $24.1 million;
- income tax expense of $16.6 million; and
- minority interest of $6.3 million.
Other items of income consisted of:
- investment income and other of $12.6 million;
- net gain on exchange rates of $2.0 million; and
- equity in net losses of affiliated companies of $0.8 million.
Our net income was $18.0 million or $0.59 per share (diluted).
Our revenues decreased $71.8 million, or 47 percent, during the year ended
December 31, 1998 compared with 1997. This was due to reduced oil sales revenue
in Venezuela as a result of declines in world crude oil prices and a 21 percent
decrease in oil sales quantities largely due to operational problems with
certain high volume wells. Sales quantities for the year ended December 31, 1998
from Venezuela were 12.2 MMBbls compared with 15.4 MMBbls for the year ended
December 31, 1997. Prices for crude oil averaged $6.75 per Bbl (pursuant to
terms of an operating service agreement) from Venezuela for the year ended
December 31, 1998 compared with $10.01 per Bbl for the year ended December 31,
1997.
Our operating expenses increased $4.9 million, or 14 percent, during the year
ended December 31, 1998 compared with 1997. This was primarily due to continuing
maturation of the Uracoa oil field in Venezuela resulting in higher water
handling, natural gas handling, workover, transportation and chemical costs. The
increase was partially offset by reduced oil production in Venezuela. Depletion,
depreciation and amortization decreased $11.3 million, or 25 percent, during the
year ended December 31, 1998 compared with 1997. This was primarily due to
write-downs of oil and natural gas properties and reduced oil sales in Venezuela
in 1998, partially offset by increased capital requirements in Venezuela.
Depletion expense per barrel of oil produced from Venezuela during the year
ended
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December 31, 1998 was $2.62 compared with $2.83 during the previous year.
Additionally, we recognized write-downs of oil and gas properties during 1998 in
the Venezuelan cost center of $187.8 million pursuant to the ceiling limitation
prescribed by the full cost method of accounting. The write-downs were a result
of the effect of declines in world crude oil prices on the prices realized by us
for our Venezuelan oil sales. We also recognized $6.1 million of impairment
expense associated with certain exploration activities. General and
administrative expenses increased $3.8 million, or 21 percent, during the year
ended December 31, 1998 compared with 1997. This was primarily due to an
allowance for doubtful accounts related to amounts owed to us by our former
Chief Executive Officer (see Note 14 of the Notes to Consolidated Financial
Statements) and costs incurred in our China operation. Taxes other than on
income decreased $1.7 million, or 31 percent, during the year ended December 31,
1998 compared to 1997. This was primarily due to decreased Venezuelan municipal
taxes, which are a function of oil revenues.
Investment income and other increased $1.4 million, or 11 percent, during the
year ended December 31, 1998 compared with 1997. This increase was due to higher
average cash and marketable securities balances. Interest expense increased $7.9
million, or 33 percent, during the year ended December 31, 1998 compared with
1997. This increase was primarily due to the issuance of $115 million in senior
unsecured notes in November 1997. Net gain on exchange rates decreased $0.2
million, or 10 percent for the year ended December 31, 1998 compared with 1997
due to changes in the value of the Bolivar. We realized a loss before income
taxes and minority interest of $226.3 million during the year ended December 31,
1998 compared with income of $42.1 million in 1997. This resulted in a decrease
in income tax expense of $41.5 million or 250 percent primarily due to decreased
taxable income in Venezuela as a result of the write-downs of oil and gas
properties. The net income attributable to the minority interest decreased $29.2
million, or 463 percent for 1998 compared with 1997 as a result of the decreased
profitability of Benton-Vinccler's operations in Venezuela.
Equity in net losses of affiliated companies were $5.1 million for the year
ended December 31, 1998 compared with equity in net losses of affiliated
companies of $0.8 million in 1997. The increase of $4.3 million was due to
reduced income from Geoilbent. Our share of revenues from Geoilbent were $8.1
million for the year ended September 30, 1998 compared with revenues of $9.9
million for the year ended September 30, 1997. The decrease of $1.8 million, or
18 percent, was due to lower average oil prices partially offset by higher sales
quantities. Prices for Geoilbent's crude oil averaged $8.72 per Bbl during the
year ended September 30, 1998 compared with $11.72 per Bbl for the year ended
September 30, 1997. Our share of Geoilbent oil sales quantities increased by
43,454 Bbls, or 5 percent, from 880,148 Bbls sold during the year ended
September 30, 1997 to 923,602 Bbls sold during the year ended September 30,
1998. The increase in oil sales was primarily due to the development of the
North Gubkinskoye Field in Western Siberia region of Russia.
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 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 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
Bbls 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 cash and a 5 percent
carried working interest in up to four wells that may be drilled in the future.
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.
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
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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.
A 3-D seismic survey has been conducted over the southwestern portion of, and a
371 kilometer 2-D seismic survey has been acquired for, the Delta Centro Block
in Venezuela. During 1999, the Block's first exploration well, the Jarina 1-X,
penetrated a thick potential reservoir sequence, but encountered no commercial
hydrocarbons. Our total cost of acquiring seismic data and drilling the Jarina
1-X was $15.4 million as December 31, 2000. In January 2001, we and our bidding
partners reached an agreement with Corporacion Venezolana del Petroleo, S.A. to
terminate the contract and our exploration obligation in exchange for the unused
portion of the standby letter of credit of $7.7 million.
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
December 31, 2000, we had recorded no proved reserves attributable to this
petroleum contract.
In August 1997, we acquired the rights to an Exploration and Production Sharing
Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to explore,
develop and produce the Sirhan Block in southeastern Jordan. Under the terms of
the PSA, we were obligated to make certain capital and operating expenditures in
up to three phases over eight years. We were obligated to spend $5.1 million in
the first exploration phase, which was extended to May 2000, for which we posted
a $1 million standby letter of credit, collateralized in full by a time deposit.
During the first quarter of 1998, we reentered two wells and tested two
different reservoirs. The WS-9 well tested significant, but non-commercial
amounts of natural gas; the WS-10 well resulted in no commercial amounts of
hydrocarbons. Therefore, at December 31, 1998, we wrote down $3.7 million in
capitalized costs incurred to date related to the PSA. During 1999, we incurred
an additional $0.3 million in capitalized costs, which were written off at
December 31, 1999. As of the May 17, 2000 expiration date of the PSA, we had
elected not to complete the first exploration phase of the agreement. As a
result, during the second quarter of 2000, we recorded a liability to the NRA
for the obligation remaining under the PSA resulting in impairment expense of
$1.0 million. The NRA collected on the letter of credit in August 2000.
In April 1998, we signed an agreement to earn a 40 percent equity interest in
Arctic Gas Company, formerly Severneftegaz. Arctic Gas owns the exclusive rights
to evaluate, develop and produce the natural gas, condensate and oil reserves in
the Samburg and Yevo-Yakha license blocks in West Siberia. The two blocks
comprise 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 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 significant
influence it exercises 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 December 31, 2000, we had loaned $22.0 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
9 percent equity interest. From December 1998 through November 2000, we
purchased shares representing an additional 20 percent equity interest not
subject to any
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sale or transfer restrictions. We owned a total of 60 percent of the
outstanding voting shares of Arctic Gas as of December 31, 2000, of which
approximately 29 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 Field 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 field during the third quarter of 1992 with
the construction of a 37-mile oil pipeline and installation of temporary
production facilities.
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 increased to 34 Euros per ton
(approximately $3.80 per barrel) on November 3, 2000 from 15 Euros per ton in
1999. 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 year ended December 31, 2000, our net foreign exchange gains
attributable to our Venezuelan and Russian operations were $0.3 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.
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.
COST REDUCTIONS
In an effort to reduce general and administrative expenses, we reduced our
administrative and technical staff in Carpinteria by 10 people in October 1999.
In connection with the reduction in workforce, we recorded termination benefits
expenses in October 1999 of $0.8 million. All amounts were paid as of December
31, 2000.
RISK FACTORS
In addition to the other information set forth elsewhere in this Form 10-K, the
following factors should be carefully considered when evaluating the Company.
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OIL PRICE DECLINES AND VOLATILITY COULD ADVERSELY AFFECT OUR REVENUE, CASH FLOWS
AND PROFITABILITY. Prices for oil fluctuate widely. The average price we
received for oil in Venezuela increased from approximately $9.21 per Bbl for the
year ended December 31, 1999, to $14.94 per Bbl for the year ended December 31,
2000. During the same period, the average price we received for oil in Russia
increased from $7.68 per Bbl to $17.45 per Bbl. Our Venezuelan oil sales are
based on a fee adjusted quarterly by the percentage change of a basket of crude
oil prices instead of by absolute dollar changes, which dampens both any upward
and downward effects of changing prices on our Venezuelan oil sales and cash
flows. Our revenues, profitability and future rate of growth depend
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. In addition, we may have ceiling test writedowns when prices decline.
Lower prices may also reduce the amount of oil that we can produce economically.
We cannot predict future oil prices. Factors that can cause this fluctuation
include:
- relatively minor changes in the supply of and demand for oil;
- market uncertainty;
- the level of consumer product demand;
- weather conditions;
- domestic and foreign governmental regulations;
- the price and availability of alternative fuels;
- political and economic conditions in oil producing countries,
particularly those in the Middle East; and
- overall economic conditions.
WE MAY NOT HAVE AVAILABLE FUNDING TO EXECUTE OUR DRILLING PROGRAMS. We have
historically addressed our long-term liquidity needs through the issuance of
debt and equity securities and the use of cash provided by operating activities.
We continue to examine the following alternative sources of long-term capital:
- sales of properties;
- joint venture financing;
- the issuance of non-recourse production-based financing;
- the sale of common stock, preferred stock or other equity
securities;
- bank borrowings or the issuance of debt securities;
- sales of prospects and technical information.
The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, oil prices and our value and
performance. We may be unable to execute our planned drilling program if we
cannot obtain capital from these sources.
ESTIMATES OF OIL AND NATURAL GAS RESERVES ARE UNCERTAIN AND INHERENTLY
IMPRECISE. This Form 10-K contains estimates of our proved oil and natural gas
reserves and the estimated future net revenues from such reserves. These
estimates are based upon various assumptions, including assumptions required by
the Securities and Exchange Commission relating to oil and natural gas prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds.
The process of estimating oil and natural gas reserves is complex. Such process
requires significant decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data for each reservoir.
Therefore, these estimates are inherently imprecise. Actual future production,
oil and natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas reserves most likely
will vary from those estimated. Any significant variance could materially affect
the estimated quantities and present value of reserves set forth. In addition,
we may adjust estimates of proved reserves to reflect production history,
results of exploration and development, prevailing oil and natural gas prices
and other factors, many of which are beyond our control. Actual production,
revenue, taxes, development expenditures and operating expenses with respect to
our reserves will likely vary from the estimates used. Such variances may be
material.
At December 31, 2000, approximately 57 percent of our estimated proved reserves
were undeveloped. Undeveloped reserves, by their nature, are less certain.
Recovery of undeveloped reserves requires significant capital expenditures and
successful drilling operations. The estimates of our future reserves include the
assumption that we will make significant capital expenditures to develop these
reserves. Although we have prepared estimates of our oil and natural gas
reserves and the costs associated with these reserves in accordance with
industry standards, we cannot assure you that the estimated costs are accurate,
that development will occur as scheduled or that the results will be as
estimated. See Supplemental Information on Oil and Natural Gas Producing
Activities.
You should not assume that the present value of future net revenues referred to
is the current market value of our estimated oil and natural gas reserves. In
accordance with Securities and Exchange Commission requirements, the estimated
discounted future net cash flows from proved reserves are generally based on
prices and costs as of the date of the estimate. Actual future prices and costs
may be materially higher or lower than the prices and costs as of the date of
the estimate. Any changes in consumption or in governmental
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regulations or taxation will also affect actual future net cash flows. The
timing of both the production and the expenses from the development and
production of oil and gas properties will affect the timing of actual future net
cash flows from estimated proved reserves and their present value. In addition,
the 10 percent discount factor, which is required by the Securities and Exchange
Commission to be used in calculating discounted future net cash flows for
reporting purposes, is not necessarily the most accurate discount factor. The
effective interest rate at various times and our risks or the risks associated
with the oil and natural gas industry in general will affect the accuracy of the
10 percent discount factor.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS. As of December 31, 2000, our
long-term debt was $213 million. Our long-term debt represented 94 percent of
our total capitalization at December 31, 2000. Our level of debt affects our
operations in several important ways, including the following:
- a significant portion of our cash flow from operations is used
to pay interest on borrowings;
- the covenants contained in the indentures governing our debt
limit our ability to borrow additional funds or to dispose of
assets;
- the covenants contained in the indentures governing our debt
affect our flexibility in planning for, and reacting to, changes
in business conditions;
- the high level of debt could impair our ability to obtain
additional financing in the future for working capital, capital
expenditures, acquisitions, general corporate or other purposes;
and
- the terms of the indentures governing our debt permit our
creditors to accelerate payments upon an event of default or a
change of control.
The intrinsic value of our assets is burdened by a heavy debt load and
constraints on capital to optimize our producing properties in Venezuela and
develop our unexploited acreage in Russia. A high level of debt increases the
risk that we may default on our debt obligations. Our ability to meet our debt
obligations and to reduce our level of debt depends on our future performance
and crude oil and natural gas realizations. General economic conditions and
financial, business and other factors affect our operations and our future
performance. Many of these factors are beyond our control. If we are unable to
repay our debt at maturity out of cash on hand, we could attempt to refinance
such debt, or repay such debt with the proceeds of any equity offering, or sell
all or part of our assets in Venezuela and Russia, or some combination thereof.
Factors that will affect our ability to raise cash through an offering of our
capital stock or a refinancing of our debt include financial market conditions
and our value and performance at the time of such offering or other financing.
We cannot assure you that any such offering or refinancing can be successfully
completed.
LOWER OIL AND NATURAL GAS PRICES MAY CAUSE US TO RECORD CEILING LIMITATION
WRITEDOWNS. We use the full cost method of accounting to report our oil and
natural gas operations. Accordingly, we capitalize the cost to acquire, explore
for and develop oil and gas properties. Under full cost accounting rules, the
net capitalized costs of oil and gas properties may not exceed a "ceiling limit"
which is based upon the present value of estimated future net cash flows from
proved reserves, discounted at 10 percent, plus the lower of cost or fair market
value of unproved properties. If net capitalized costs of oil and gas properties
exceed the ceiling limit, we must charge the amount of the excess to earnings.
This is called a "ceiling limitation write-down." This charge does not impact
cash flow from operating activities, but does reduce stockholders' equity. The
risk that we will be required to write down the carrying value of our oil and
gas properties increases when oil and natural gas prices are low or volatile. In
addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves. In 1998, we recorded after-tax
write-downs of $158.5 million ($187.8 million pre-tax). In 1999 and 2000, we
recorded no ceiling limitation write-downs. We cannot assure you that we will
not experience ceiling limitation write-downs in the future.
WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES. In general, the
volume of production from oil and gas properties declines as reserves are
depleted. The decline rates depend on reservoir characteristics. Our reserves
will decline as they are produced unless we acquire properties with proved
reserves or conduct successful exploration and development activities. Our
future oil production is highly dependent upon our level of success in finding
or acquiring additional reserves. The business of exploring for, developing or
acquiring reserves is capital intensive and uncertain. We may be unable to make
the necessary capital investment to maintain or expand our oil and natural gas
reserves if cash flow from operations is reduced and external sources of capital
become limited or unavailable. We cannot assure you that our future exploration,
development and acquisition activities will result in additional proved reserves
or that we will be able to drill productive wells at acceptable costs.
OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND NATURAL GAS DRILLING AND
PRODUCTION ACTIVITIES. Oil and natural gas drilling and production activities
are subject to numerous risks, including the risk that no commercially
productive oil or natural gas reservoirs will be found. The cost of drilling and
completing wells is often
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uncertain. Oil and natural gas drilling and production activities may be
shortened, delayed or canceled as a result of a variety of factors, many of
which are beyond our control. These factors include:
- unexpected drilling conditions;
- pressure or irregularities in formations;
- equipment failures or accidents;
- weather conditions; and
- shortages in experienced labor or shortages or delays in the
delivery of equipment.
The prevailing price of oil also affects the cost of and the demand for drilling
rigs, production equipment and related services. We cannot assure you that the
new wells we drill will be productive or that we will recover all or any portion
of our investment. Drilling for oil and natural gas may be unprofitable.
Drilling activities can result in dry wells and wells that are productive but do
not produce sufficient net revenues after operating and other costs.
THE OIL AND NATURAL GAS INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS. The oil
and natural gas industry experiences numerous operating risks. These operating
risks include the risk of fire, explosions, blow-outs, pump and pipe failures,
abnormally pressured formations and environmental hazards. Environmental hazards
include oil spills, natural gas leaks, pipeline ruptures or discharges of toxic
gases. If any of these industry operating risks occur, we could have substantial
losses. Substantial losses may be caused by injury or loss of life, severe
damage to or destruction of property, natural resources and equipment, pollution
or other environmental damage, clean-up responsibilities, regulatory
investigation and penalties and suspension of operations. In accordance with
industry practice, we maintain insurance against some, but not all, of the risks
described above. We cannot assure you that our insurance will be adequate to
cover losses or liabilities. Also, we cannot predict the continued availability
of insurance at premium levels that justify its purchase.
OUR CONCENTRATION OF ASSETS INCREASES OUR EXPOSURE TO PRODUCTION DECLINES.
During 2000, the production from the South Monagas Unit in Venezuela represented
approximately 100 percent of our total production from consolidated companies.
Our production, revenue and cash flow will be adversely affected if production
from the South Monagas Unit decreases significantly.
OUR INTERNATIONAL OPERATIONS MAY BE ADVERSELY AFFECTED BY CURRENCY FLUCTUATIONS
AND ECONOMIC AND POLITICAL DEVELOPMENTS. We have substantially all of our
operations in Venezuela and Russia. The expenses of such operations are payable
in local currency while most of the revenue from oil sales is paid in U.S.
dollars. As a result, our operations are subject to the risk of fluctuations in
the relative value of the Bolivar, Ruble and U.S. dollar. Our foreign operations
may also be adversely affected by political and economic developments, royalty
and tax increases and other laws or policies in these countries, as well as U.S.
policies affecting trade, taxation and investment in other countries.
COMPETITION WITHIN THE INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS. We operate
in a highly competitive environment. We compete with major and independent oil
and natural gas companies for the acquisition of desirable oil and gas
properties and the equipment and labor required to develop and operate such
properties. Many of these competitors have financial and other resources
substantially greater than ours.
OUR OIL AND NATURAL GAS OPERATIONS ARE SUBJECT TO VARIOUS GOVERNMENTAL
REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS. Our oil and natural gas
operations are subject to various foreign governmental regulations. These
regulations may be changed in response to economic or political conditions.
Matters regulated include permits for discharges of wastewaters and other
substances generated in connection with drilling operations, bonds or other
financial responsibility requirements to cover drilling contingencies and well
plugging and abandonment costs, reports concerning operations, the spacing of
wells, and unitization and pooling of properties and taxation. At various times,
regulatory agencies have imposed price controls and limitations on oil and gas
production. In order to conserve supplies of oil and natural gas, these agencies
have restricted the rates of flow of oil and natural gas wells below actual
production capacity. In addition, our operations are subject to taxation
policies, that in Russia have changed significantly. We cannot predict the
ultimate cost of compliance with these requirements or their effect on our
operations.
FOREIGN OPERATIONS RISK. Our operations in areas outside the U.S. are subject to
various risks inherent in foreign operations. These risks may include, among
other things, loss of revenue, property and equipment as a result of hazards
such as expropriation, war, insurrection and other political risks, increases in
taxes and governmental royalties, renegotiation of contracts with governmental
entities, changes in laws and policies governing operations of foreign-based
companies, currency restrictions and exchange rate fluctuations and other
uncertainties arising out of foreign government sovereignty over the Company's
international operations. Our international operations may also be adversely
affected by laws and policies of the United States affecting foreign trade and
taxation. To date, our international operations have not been materially
affected by these risks.
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ITEM 7A. 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 Bbl in 1997 to
$6.75 per Bbl in 1998 and increased to $14.94 per Bbl in 2000. Based on our
budgeted production and costs, we will require an average realization in
Venezuela of approximately $12.50 per Bbl 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 1999
or 2000.
INTEREST RATES
Total long-term debt at December 31, 2000, consisted of $213 million of
fixed-rate senior unsecured notes maturing in 2003 ($108 million) and 2007 ($105
million). A hypothetical 10 percent adverse change in the floating rate would
not have had a material affect on our results of operations for the year ended
December 31, 2000.
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The information required by this item is included herein on pages S-1 through
S-33.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported under this item.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
*
ITEM 11. EXECUTIVE COMPENSATION
*
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
*
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
*
* Reference is made to information under the captions "Election of
Directors", "Executive Officers", "Executive Compensation", "Security
Ownership of Certain Beneficial Owners and Management", and "Certain
Relationships and Related Transactions" in our Proxy Statement for the 2001
Annual Meeting of Stockholders. If our Proxy Statement is not disseminated
prior to April 30, 2001, we will file an amendment of Part III of Form 10-K
on or before that date.
42
42
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) 1. Index to Financial Statements: Page
----
Reports of Independent Accountants ................................S-1
Consolidated Balance Sheets at December 31, 2000 and 1999 .........S-2
Consolidated Statements of Operations for the Years Ended
December 31, 2000, 1999 and 1998...................................S-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2000, 1999 and 1998.......................S-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998...................................S-5
Notes to Consolidated Financial Statements.........................S-7
2. Consolidated Financial Statement Schedules:
Schedule II - Valuation and Qualifying Accounts
3. Exhibits:
3.1 Certificate of Incorporation filed September 9, 1988
(Incorporated by reference to Exhibit 3.1 to our
Registration Statement (Registration No. 33-26333).
3.2 Amendment to Certificate of Incorporation filed June 7, 1991
(Previously filed as an exhibit to our S-1 Registration
Statement (Registration No. 33-39214)).
3.3 Restated Bylaws.
4.1 Form of Common Stock Certificate (Previously filed as an
exhibit to our S-1 Registration Statement (Registration No.
33-26333)).
10.4 Form of Employment Agreements (Exhibit 10.19) (Previously
filed as an exhibit to our S-1 Registration Statement
(Registration No. 33-26333)).
10.7 Benton Oil and Gas Company 1991-1992 Stock Option Plan
(Exhibit 10.14) (Previously filed as an exhibit to our S-1
Registration Statement (Registration No. 33-43662)).
10.8 Benton Oil and Gas Company Directors' Stock Option Plan
(Exhibit 10.15) (Previously filed as an exhibit to our S-1
Registration Statement (Registration No. 33-43662)).
10.9 Agreement dated October 16, 1991 among Benton Oil and Gas
Company, Puror State Geological Enterprises for Survey,
Exploration, Production and Refining of Oil and Gas; and
Puror Oil and Gas Production Association (Exhibit 10.14)
(Previously filed as an exhibit to our S-1 Registration
Statement (Registration No. 33-46077)).
43
43
10.10 Operating Service Agreement between Benton Oil and Gas
Comany and Lagoven, S.A., which has been subsequently
combined into PDVSA Petroleo y Gas, S.A., dated July 31,
1992, (portions have been omitted pursuant to Rule 406
promulgated under the Securities Act of 1933 and filed
separately with the Securities and Exchange
Commission--Exhibit 10.25) (Previously filed as an exhibit
to our S-1 Registration Statement (Registration No.
33-52436)).
10.16 Indenture dated May 2, 1996 between Benton Oil and Gas
Company and First Trust of New York, National Association,
Trustee related to $125,000,000, 11 5/8 percent Senior Notes
Due 2003 (Incorporated by reference to Exhibit 4.1 to our
S-4 Registration Statement filed June 17, 1996, SEC
Registration No. 333-06125).
10.17 Indenture dated November 1, 1997 between Benton Oil and Gas
Company and First Trust of New York, National Association,
Trustee related to an aggregate of $115,000,000 principal
amount of 9 3/8 percent Senior Notes due 2007 (Incorporated
by reference to Exhibit 10.1 to our Form 10-Q for the
quarter ended September 30, 1997).
10.18 Separation Agreement dated January 4, 2000 between Benton
Oil and Gas Company and Mr. A.E. Benton. (Incorporated by
reference to Exhibit 10.18 to our Form 10-K for the year
ended December 31, 1999).
10.19 Consulting Agreement dated January 4, 2000 between Benton
Oil and Gas Company and Mr. A.E. Benton. (Incorporated by
reference to Exhibit 10.19 to our Form 10-K for the year
ended December 31, 1999).
10.20 Employment Agreement dated July 10, 2000 between Benton Oil
and Gas Company and Peter J. Hill. (Incorporated by
reference to Exhibit 10.20 to our Form 8-K, filed June 6,
2000).
10.21 Benton Oil and Gas Company 1999 Employee Stock Option Plan.
10.22 Benton Oil and Gas Company Non-Employee Director Stock
Purchase Plan.
10.23 Employment Agreement dated December 7, 2000 between Benton
Oil and Gas Company and Steven W. Tholen.
21.1 List of subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Huddleston & Co., Inc.
23.3 Consent of Ryder Scott Company, L.P.
27.1 Financial Data Schedule.
- -----------------
(b) Reports on Form 8-K
On October 21, 2000, we filed a report on Form 8-K, under Item 5,
"Other Events" regarding the expansion of the board of directors to
eight members and the election of five new members.
44
44
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Board of Directors
and Stockholders of Benton Oil and Gas Company
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, stockholders' equity (deficit) and cash
flows present fairly, in all material respects, the financial position of Benton
Oil and Gas Company and its subsidiaries at December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the related financial statement schedule presents fairly, in all material
respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. These financial statements and
financial statement schedule are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the financial statements, in 1999 the Company changed
its method of reporting its investment in Geoilbent.
PricewaterhouseCoopers LLP
Los Angeles, California
March 23, 2001
S-1
45
45
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
(in thousands)
DECEMBER 31,
2000 1999
---- ----
ASSETS
------
Current Assets:
Cash and cash equivalents ..................................................... $ 15,132 $ 21,147
Restricted cash ............................................................... 12 12
Marketable securities ......................................................... 1,303 4,469
Accounts and notes receivable:
Accrued oil and natural gas sales .......................................... 38,003 27,339
Joint interest and other, net .............................................. 6,778 4,993
Prepaid expenses and other .................................................... 2,404 1,635
--------- ---------
Total Current Assets .................................................... 63,632 59,595
Restricted Cash .................................................................. 10,920 46,449
Other Assets ..................................................................... 5,891 10,569
Deferred Income Taxes ............................................................ 4,293 12,186
Investments In and Advances To Affiliated Companies .............................. 77,741 61,357
Property and Equipment:
Oil and gas properties (full cost method-costs of $16,634 and $16,117
excluded from amortization in 2000 and 1999, respectively) ................. 490,548 435,449
Furniture and fixtures ........................................................ 11,049 10,031
--------- ---------
501,597 445,480
Accumulated depletion, impairment and depreciation ............................ (377,627) (359,325)
--------- ---------
Total Property and Equipment ............................................ 123,970 86,155
--------- ---------
$ 286,447 $ 276,311
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
---------------------------------------------
Current Liabilities:
Accounts payable, trade and other ............................................. $ 12,804 $ 3,317
Accrued expenses .............................................................. 25,102 17,105
Accrued interest payable ...................................................... 3,733 4,686
Income taxes payable .......................................................... 3,909 2,392
Short-term borrowings ......................................................... 5,714 -
Current portion of long-term debt ............................................. - 2
--------- ---------
Total Current Liabilities ............................................... 51,262 27,502
Long-Term Debt ................................................................... 213,000 264,575
Commitments and Contingencies .................................................... - -
Minority Interest ................................................................ 9,281 1,412
Stockholders' Equity (Deficit):
Preferred stock, par value $0.01 a share; Authorized 5,000
shares; outstanding, none
Common stock, par value $0.01 a share; Authorized 80,000 shares at December
31, 2000 and 1999; issued 33,872 and 29,627 shares
at December 31, 2000 and 1999 .............................................. 339 296
Additional paid-in capital .................................................... 156,629 147,078
Retained deficit .............................................................. (143,365) (163,853)
Treasury stock, at cost, 50 shares ............................................ (699) (699)
--------- ---------
Total Stockholders' Equity (Deficit) .................................... 12,904 (17,178)
--------- ---------
$ 286,447 $ 276,311
========= =========
See accompanying notes to consolidated financial statements
S-2
46
46
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
(in thousands, except per share data)
YEARS ENDED DECEMBER 31,
------------------------
2000 1999 1998
---- ---- ----
REVENUES
Oil and natural gas sales ............................................ $ 140,284 $ 89,060 $ 82,212
---------- ---------- ----------
140,284 89,060 82,212
---------- ---------- ----------
EXPENSES
Operating expenses ................................................... 47,430 39,393 40,066
Depletion, depreciation and amortization ............................. 17,175 16,519 33,157
Write-down of oil and gas properties and impairments ................. 1,346 25,891 193,893
General and administrative ........................................... 16,739 25,969 21,485
Taxes other than on income ........................................... 4,390 3,813 3,677
---------- ---------- ----------
87,080 111,585 292,278
---------- ---------- ----------
Income (Loss) from Operations ........................................... 53,204 (22,525) (210,066)
Other Non-Operating Income (Expense)
Investment earnings and other ........................................ 8,559 8,986 13,982
Interest expense ..................................................... (28,973) (29,247) (32,007)
Net gain on exchange rates ........................................... 326 1,044 1,767
---------- ---------- ----------
(20,088) (19,217) (16,258)
---------- ---------- ----------
Income (Loss) from Consolidated Companies Before Income
Taxes and Minority Interests ......................................... 33,116 (41,742) (226,324)
Income Tax Expense (Benefit) ............................................ 14,032 (7,526) (24,911)
---------- ---------- ----------
Income (Loss) Before Minority Interests ................................. 19,084 (34,216) (201,413)
Minority Interests in Consolidated Subsidiary Companies ................. 7,869 937 (22,895)
---------- ---------- ----------
Income (Loss) from Consolidated Companies ............................... 11,215 (35,153) (178,518)
Equity in Net Earnings (Losses) of Affiliated Companies ................. 5,313 2,869 (5,062)
---------- ---------- ----------
Income (Loss) Before Extraordinary Income ............................... 16,528 (32,284) (183,580)
Extraordinary Income on Debt Repurchase, Net of Tax of $0 ............... 3,960 - -
---------- ---------- ----------
Net Income (Loss) ....................................................... $ 20,488 $ (32,284) $ (183,580)
========== ========== ==========
Net Income (Loss) Per Common Share:
Basic:
Income (Loss) before extraordinary income ........................... $ 0.54 $ (1.09) $ (6.21)
Extraordinary Income ................................................ 0.13 - -
---------- ---------- ----------
Net Income (Loss) ................................................... $ 0.67 $ (1.09) $ (6.21)
========== ========== ==========
Diluted:
Income (Loss) Before Extraordinary Income ........................... $ 0.53 $ (1.09) $ (6.21)
Extraordinary Income ................................................ 0.13 - -
---------- ---------- ----------
Net Income (Loss) ................................................... $ 0.66 $ (1.09) $ (6.21)
========== ========== ==========
See accompanying notes to consolidated financial statements.
S-3
47
47
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity (Deficit)
(in thousands)
EMPLOYEE
COMMON ADDITIONAL RETAINED NOTE
SHARES COMMON PAID-IN EARNINGS TREASURY RECEIVABLE,
ISSUED STOCK CAPITAL (DEFICIT) STOCK NET TOTAL
------- ----- -------- --------- ----- ------- ---------
BALANCE AT JANUARY 1, 1998 ................ 29,522 $ 295 $146,125 $ 52,011 $(699) $ - $ 197,732
Issuance of common shares:
Exercise of stock options ............. 105 1 794 - - - 795
Extension of warrants ................. - - 135 - - - 135
Employee note receivable, net ............. - - - - - (2,093) (2,093)
Net loss .................................. - - - (183,580) - - (183,580)
------- ----- -------- --------- ----- ------- ---------
BALANCE AT DECEMBER 31, 1998 .............. 29,627 296 147,054 (131,569) (699) (2,093) 12,989
Issuance of common shares:
Extension of warrants ................. - - 24 - - - 24
Employee note receivable, net ............. - - - - - 2,093 2,093
Net loss .................................. - - - (32,284) - - (32,284)
------- ----- -------- --------- ----- ------- ---------
BALANCE AT DECEMBER 31, 1999 .............. 29,627 296 147,078 (163,853) (699) - (17,178)
Issuance of common shares:
Exercise of stock options ............. 85 1 316 - - - 317
Extension of warrants ................. - - 12 - - - 12
Repurchase of debt .................... 4,160 42 9,223 - - - 9,265
Net income ................................ - - - 20,488 - - 20,488
------- ----- -------- --------- ----- ------- ---------
BALANCE AT DECEMBER 31, 2000 .............. 33,872 $ 339 $156,629 $(143,365) $(699) $ - $ 12,904
======= ===== ======== ========= ===== ======= =========
See accompanying notes to consolidated financial statements
S-4
48
48
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(in thousands)
YEARS ENDED DECEMBER 31,
------------------------
2000 1999 1998
---- ---- ----
Cash Flows From Operating Activities:
Net income (loss) .......................................................... $ 20,488 $ (32,284) $(183,580)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depletion, depreciation and amortization ................................ 17,175 16,519 33,157
Write-down and impairment of oil and gas properties ..................... 1,346 25,891 193,893
Amortization of financing costs ......................................... 1,375 1,396 1,442
Loss on disposition of assets ........................................... 60 44 74
Equity in (earnings) losses of affiliated companies ..................... (5,313) (2,869) 5,062
Allowance and write off of employee notes and accounts receivable ....... 331 6,231 2,900
Minority interest in undistributed earnings (losses) of subsidiaries .... 7,869 937 (22,893)
Extraordinary income from repurchase of debt ............................ (3,960) - -
Deferred income taxes ................................................... 7,893 (9,210) (27,787)
Changes in operating assets and liabilities:
Accounts and notes receivable ........................................... (12,780) (6,414) 18,436
Prepaid expenses and other .............................................. (769) 1,750 (1,771)
Accounts payable ........................................................ 9,487 (3,142) (16,410)
Accrued interest payable ................................................ (953) (711) (131)
Accrued expenses ........................................................ 7,997 (166) 2,468
Income taxes payable .................................................... 1,517 636 (2,704)
--------- --------- ---------
Net Cash Provided by (Used In) Operating Activities ..................... 51,763 (1,392) 2,156
--------- --------- ---------
Cash Flows from Investing Activities:
Proceeds from sale of property and equipment ............................... 800 15,100 -
Additions of property and equipment ........................................ (57,196) (36,984) (101,917)
Investment in and advances to affiliated companies ......................... (11,071) (13,052) (17,866)
Increase in restricted cash ................................................ (271) (214) (230)
Decrease in restricted cash ................................................ 35,800 19,435 8,884
Purchases of marketable securities ......................................... (12,638) (29,173) (55,438)
Maturities of marketable securities ........................................ 15,804 65,877 170,701
--------- --------- ---------
Net Cash Provided by (Used In) Investing Activities ..................... (28,772) 20,989 4,134
--------- --------- ---------
Cash Flows from Financing Activities:
Net proceeds from exercise of stock options and warrants ................... 330 24 930
Proceeds from issuance of short term borrowings and notes payable .......... 15,087 - -
Payments on short term borrowings and notes payable ........................ (47,488) (15,439) (12)
(Increase) decrease in other assets ........................................ 3,065 (233) (1,741)
--------- --------- ---------
Net Cash Used In Financing Activities ................................... (29,006) (15,648) (823)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents .................... (6,015) 3,949 5,467
Cash and Cash Equivalents at Beginning of Year ................................ 21,147 17,198 11,731
--------- --------- ---------
Cash and Cash Equivalents at End of Year ...................................... $ 15,132 $ 21,147 $ 17,198
========= ========= =========
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense ............................. $ 28,326 $ 30,346 $ 30,389
========= ========= =========
Cash paid during the year for income taxes ................................. $ 2,950 $ 2,600 $ 2,971
========= ========= =========
See accompanying notes to consolidated financial statements.
S-5
49
49
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the year ended December 31, 2000, we repurchased $12.0 million face value
of our senior unsecured notes with the issuance of 4.2 million shares of common
stock (see Note 3).
During the year ended December 31, 1999, we recorded an allowance for doubtful
accounts related to amounts owed to us by our former Chief Executive Officer,
including the portion of the note secured by our stock and stock options of $2.1
million (see Note 14).
During the year ended December 31, 1998, we reduced stockholders' equity by $2.1
million, the portion of the note receivable from our former Chief Executive
Officer secured by our stock and stock options (see Note 14).
See accompanying notes to consolidated financial statements.
S-6
50
50
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Years Ended December 31, 2000, 1999 and 1998
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 in 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"), formerly Severneftegaz, based on a fiscal year ending September
30 (see Note 2).
In January 2000, in connection with the release of Emerging Issues Task Force
(EITF) Issues Summary 00-01, "Applicability of the Pro Rata Method of
Consolidation to Investments in Certain Partnerships and Other Unincorporated
Joint Ventures", we reviewed the accounting for our investment in Geoilbent
under the proportionate consolidation method. As a result of this review, we
decided to report our investment in Geoilbent using the equity method effective
December 31, 1999. This change had no effect on net income or our proportionate
share of oil and natural gas reserves. It did, however, result in the reduction
of our reported consolidated net cash flows for the years ended December 31,
1999 and 1998 of $5.3 million and $0.7 million, respectively. For the years
ended December 31, 1999 and 1998, revenues were reduced by our proportionate
share, which was $11.1 million and $8.1 million, respectively, operating
expenses were reduced $9.1 million and $18.2 million, respectively and net other
non-operating expenses and income taxes were reduced $3.4 million and $7.2
million, respectively. Summarized financial information for Geoilbent is
included in Note 9.
REVENUE RECOGNITION
Oil and natural gas revenue is recognized when title passes to the customer.
CASH AND CASH EQUIVALENTS
Cash equivalents include money market funds and short term certificates of
deposit with original maturity dates of less than three months.
RESTRICTED CASH
Restricted cash represents cash and cash equivalents used as collateral for
financing and letter of credit and loan agreements and is classified as current
or non-current based on the terms of the agreements.
MARKETABLE SECURITIES
Marketable securities are carried at amortized cost. The marketable securities
that 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 and $4.5 million in commercial paper at
December 31, 2000 and 1999, respectively.
ACCOUNTS AND NOTES RECEIVABLE
Allowance for doubtful accounts related to employee notes at December 31, 2000
and 1999 was $6.2 million and $5.9 million, respectively (see Note 14).
Allowance for doubtful accounts related to joint interest and other accounts
receivable was $0.3 million at December 31, 2000 and 1999.
OTHER ASSETS
Other assets consist principally of costs associated with the issuance of
long-term debt. Debt issuance costs are amortized on a straight-line basis over
the life of the debt, which approximates the effective interest method of
amortizing these costs.
S-7
51
51
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. All costs
associated with the acquisition, exploration, and development of oil and natural
gas reserves are capitalized as incurred, including exploration overhead of $1.5
million, $2.1 million and $2.4 million for the years ended December 31, 2000,
1999 and 1998, respectively, and capitalized interest of $0.6 million and $2.1
million for the years ended December 31, 2000 and 1999, respectively. Only
overhead that is directly identified with acquisition, exploration or
development activities is capitalized. All costs related to production, general
corporate overhead and similar activities are expensed as incurred.
The costs of unproved properties are excluded from amortization until the
properties are evaluated. 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. During 2000, 1999
and 1998, the Company recognized $1.3 million, $25.9 million and $6.1 million,
respectively, of impairment expense associated with certain exploration
activities. Due to the unpredictable nature of exploration drilling activities,
the amount and timing of impairment expenses are difficult to predict with any
certainty.
Excluded costs at December 31, 2000 consisted of the following by year incurred
(in thousands):
TOTAL 2000 1999 1998 PRIOR TO 1998
------- ------- ------- ------- -------------
Property acquisition costs ................ $15,106 $ - $ - $ - $15,106
Exploration costs ......................... 1,528 518 46 90 874
------- ------- ------- ------- -------
$16,634 $ 518 $ 46 $ 90 $15,980
======= ======= ======= ======= =======
Substantially all of the excluded costs at December 31, 2000 relate to the
acquisition of Benton Offshore China Company and exploration related to its Wan
`An Bei property. The remaining excluded costs of $0.4 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 years ended December 31,
2000, 1999 and 1998 was $15.3 million, $14.8 million and $31.8 million ($1.68,
$1.53 and $2.62 per equivalent barrel), respectively.
A gain or loss is recognized on the sale of oil and gas properties only when the
sale involves a significant change in the relationship between costs and the
value of proved reserves or the underlying value of unproved property.
Depreciation of furniture and fixtures is computed using the straight-line
method with depreciation rates based upon the estimated useful life of the
property, generally 5 years. Leasehold improvements are depreciated over the
life of the applicable lease. Depreciation expense was $1.8 million, $1.6
million and $1.3 million for the years ended December 31, 2000, 1999 and 1998,
respectively.
The major components of property and equipment at December 31 are as follows (in
thousands):
2000 1999
---- ----
Proved property costs ................................................ $ 458,571 $ 409,526
Costs excluded from amortization ..................................... 16,634 16,117
Oilfield inventories ................................................. 15,343 9,806
Furniture and fixtures ............................................... 11,049 10,031
--------- ---------
501,597 445,480
Accumulated depletion, impairment and depreciation ................... (377,627) (359,325)
--------- ---------
$ 123,970 $ 86,155
========= =========
We perform a quarterly cost center ceiling test of our oil and gas properties
under the full cost accounting rules of the Securities and Exchange Commission.
During 1998, due to declines in world crude oil prices, the ceiling tests
resulted in write-downs of oil and gas properties in the Venezuela cost center
of $187.8 million.
S-8
52
52
TAXES ON INCOME
Deferred income taxes reflect the net tax effects, calculated at currently
enacted rates, of (a) future deductible/taxable amounts attributable to events
that have been recognized on a cumulative basis in the financial statements or
income tax returns, and (b) operating loss and tax credit carryforwards. A
valuation allowance for deferred tax assets is recorded when it is more likely
than not that the benefit from the deferred tax asset will not be realized.
FOREIGN CURRENCY
We have significant operations outside of the United States, principally in
Venezuela and Russia. Both Venezuela and Russia are considered highly
inflationary economies. As a result, operations in those countries are
re-measured in United States dollars, and all currency gains or losses are
recorded in the statement of income. We attempt to manage our operations in a
manner to reduce our exposure to foreign exchange losses. However, there are
many factors which affect foreign exchange rates and resulting exchange gains
and losses, many of which are beyond our influence. 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 United
States dollar. It is not possible to predict the extent to which we may be
affected by future changes in exchange rates.
FINANCIAL INSTRUMENTS
Our financial instruments that are exposed to concentrations of credit risk
consist primarily of cash equivalents, marketable securities and accounts
receivable. Our short-term investments are placed with a variety of financial
institutions with high credit ratings. This diversified investment policy limits
our exposure both to credit risk and to concentrations of credit risk.
Accounts receivable result from oil and natural gas exploration and production
activities and our customers and partners are engaged in the oil and natural gas
business. PDVSA Petroleo y Gas, S.A. ("PDVSA"), an affiliate of Petroleos de
Venezuela, S.A., purchases 100 percent of our Venezuelan oil production.
Although the Company does not currently foresee a credit risk associated with
these receivables, repayment is dependent upon the financial stability of PDVSA.
Our financial instruments consist primarily of cash and cash equivalents,
accounts receivable and payable, marketable securities, short-term borrowings
and long-term debt. The book values of all financial instruments, other than
long-term debt, are representative of their fair values due to their short-term
maturities. The aggregate fair value of our senior unsecured notes, based on the
last trading prices at December 31, 2000 and 1999, was approximately $137.0
million and $151.0 million, respectively.
TREASURY STOCK
In June 1997, our Board of Directors instituted a treasury stock repurchase
program under which we are authorized to purchase up to 1.5 million shares of
our common stock. The shares may be used for reissuance in connection with the
Company's employee stock option plan or for other corporate purposes. During
1997, we repurchased 50,000 shares at an average price of $13.99 per share.
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 years ended
December 31, 2000 and, in accordance with SFAS 130, have not provided a separate
statement of comprehensive income.
DERIVATIVES AND HEDGING
Statement of Financial Accounting Standards No. 133 ("SFAS 133"), as amended,
establishes accounting and reporting standards for derivative instruments and
hedging activities. The Company has not used derivative or hedging instruments
since 1996, but may consider hedging some portion of its oil production in the
future. The Company does not believe, however, that the adoption of SFAS 133
will have a material effect on its results of operations or financial position.
MINORITY INTERESTS
We record a minority interest attributable to the minority shareholders of our
Venezuela subsidiaries. The minority interests in net income and losses are
generally subtracted or added to arrive at consolidated net income. However, as
of December 31, 1998, losses attributable to
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the minority shareholder of Benton-Vinccler, our 80 percent owned subsidiary,
exceeded its interest in equity capital creating an equity deficit of $3.5
million. Accordingly, $3.5 million of income attributable to the minority
shareholder of Benton-Vinccler in 1999 was included in our consolidated net
loss, eliminating the minority shareholder's equity deficit.
USE OF ESTIMATES
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain items in 1999 and 1998 have been reclassified to conform to the 2000
financial statement presentation.
NOTE 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES
Investments in Geoilbent and Arctic Gas are accounted for using the equity
method due to the significant influence we exercise over their operations and
management. Investments include amounts paid to the investee companies for
shares of stock 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. Investment in equity in net assets of Geoilbent includes our
capital contribution of $2.0 million in December 1998 which was included in
other costs, net of amortization. During 1998, due to declines in world oil
prices, we recorded a write-down of $10.1 million related to the Geoilbent
investment. No dividends have been paid to us 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
--------------- ------------------ -----
2000 1999 2000 1999 2000 1999
---- ---- ---- ---- ---- ----
Investments:
In equity in net assets......... $ 28,056 $ 28,056 $ (2,218) $ (2,419) $ 25,838 $ 25,637
Other costs, net of amortization (202) (542) 19,058 17,128 18,856 16,586
---------- ---------- --------- ----------- --------- ---------
Total investments............... 27,854 27,514 16,840 14,709 44,694 42,223
Advances............................ - - 21,986 13,364 21,986 13,364
Equity in earnings (losses)......... 12,310 6,167 (1,249) (397) 11,061 5,770
---------- ---------- --------- ----------- --------- ---------
Total........................ $ 40,164 $ 33,681 $ 37,577 $ 27,676 $ 77,741 $ 61,357
========== ========== ========= =========== ========= =========
NOTE 3 - LONG-TERM DEBT AND LIQUIDITY
LONG-TERM DEBT
Long-term debt consists of the following at December 31 (in thousands):
2000 1999
---- ----
Senior unsecured notes with interest at 9.375%...................................... $ 105,000 $ 105,000
Senior unsecured notes with interest at 11.625%..................................... 108,000 125,000
Benton-Vinccler credit facility with interest at LIBOR plus
6.125%. Collateralized by a time deposit earning
approximately LIBOR plus 5.75% - See description below.......................... - 34,575
Other ........................................................................... - 2
----------- -----------
213,000 264,577
Less current portion................................................................ - 2
----------- -----------
$ 213,000 $ 264,575
=========== ===========
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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. 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 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. In addition, we wrote-off $0.2 million in
unamortized loan fees related to the notes resulting in an extraordinary gain of
$4.0 million. Interest on the notes is due May 1 and November 1 of each year.
The indenture agreements provide for certain limitations on liens, additional
indebtedness, certain investments and capital expenditures, dividends, mergers
and sales of assets. At December 31, 2000, we were in compliance with all
covenants of the indentures.
In August 1996, Benton-Vinccler entered into a $50 million, long-term credit
facility with Morgan Guaranty Trust Company of New York ("Morgan Guaranty") to
repay the balance outstanding under a short-term credit facility and to repay
certain advances received from us. In August 1999, Benton-Vinccler repaid $15.4
million of the long-term credit facility with proceeds from the sale of certain
equipment located in the South Monagas Unit (see Note 10) and in October 2000
Benton-Vinccler reduced the credit facility to $31.6 million. In December 2000,
the credit facility was fully repaid.
The principal payment requirements for our long-term debt outstanding at
December 31, 2000 are as follows (in thousands):
2001............................................... $ -
2002............................................... -
2003............................................... 108,000
2004............................................... -
2005............................................... -
Subsequent Years................................... 105,000
-----------
$ 213,000
===========
In March 2001, Benton-Vinccler borrowed $12.3 million, 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 5 years. The second loan, in
the amount of 4.4 billion Venezuelan Bolivars ($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 initial quarterly period is 16.5%.
LIQUIDITY
As a result of Benton's increased leverage and poor investment returns since
1998, 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 aimed at creating new
stockholder value, we undertook several significant actions beginning in 2000,
including:
- Hired a new President and Chief Executive Officer, a new Senior Vice
President and Chief Financial Officer and a new Vice President and
General Counsel;
- Reconstituted our Board of Directors with industry executives with
proven experience in oil and natural gas operations, finance and
international operations;
- Redefined our strategic priorities to focus on value creation;
- Initiated capital conservation steps and financial transactions to
de-leverage the company and improve cash flow for reinvestment;
- Undertook a comprehensive study of our core Venezuelan asset to
attempt to enhance the value of its production, thus ultimately
increasing cash flow and potentially extending its productive life.
We continue to aggressively explore means by which to maximize stockholder
value. We believe that Benton possesses significant producing properties in
Venezuela which have yet to be optimized and valuable unexploited acreage in
Venezuela and Russia. The intrinsic value of Benton's assets is burdened by a
heavy debt load and constraints on capital to further exploit such
opportunities.
Therefore, we, with the advice of its financial and legal advisors, are
conducting a comprehensive review of strategic alternatives, including, but not
limited to, selling all or part of its existing assets in Venezuela and Russia,
debt restructuring, some combination thereof, 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.
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As a result of the decline in oil prices, we instituted in 1998, and continued
in 1999, 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 increased substantially and we concluded an analysis of
our strategic alternatives. 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
Note10). During 2000, we drilled 26 oil wells in the Uracoa Field under the
alliance agreements utilizing Schlumberger's technical and engineering
resources.
While no assurance can be given, we currently believe that our capital resources
and liquidity will be adequate to fund our planned capital expenditures,
investments in and advances to affiliates and semiannual interest payment
obligations for the next twelve (12) months. This expectation is based upon 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 is a significant decrease in either price or
production levels related to the South Monagas Unit. Future cash flows are
subject to a number of variables including, but not limited to, the level of
production and prices, as well as various economic conditions that have
historically affected the oil and 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.
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. The current interest rate on the facility is 16.5 percent. In
December 2000, we borrowed 4 billion Bolivars (approximately $5.7 million) under
this facility at an interest rate of 12.5 percent, which we repaid in January
2001.
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 shareholders of further issuances in excess of 5.9 million
shares of common stock in exchange for senior notes will be to materially dilute
the existing shareholders if material portions of the senior notes are
exchanged. The dilutive effect on the common stockholders would depend upon a
number of factors, the primary ones being the number of shares issued, the price
at which the common stock is issued and the discount on the senior notes
exchanged.
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 filed suit in the
Unites 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 have been filed. We believe that
this case lacks merit and that an unfavorable outcome is unlikely.
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
which is expected to have a material adverse effect on our financial position,
results of operations or liquidity.
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In May 1996, we entered into an agreement with Morgan Guaranty that provided for
an $18 million cash collateralized 5-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 as of
December 31, 2000. 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 November 1997, we entered into an agreement with Morgan Guaranty which
provided for a $1 million cash collateralized 2-year letter of credit, which was
extended to November 2000, to secure our obligations under the first exploration
phase of a Production Sharing Agreement ("PSA") with Jordan's Natural Resources
Authority ("NRA") (see Note 13). At the May 17, 2000 expiration date of the PSA,
we had not completed our obligation under the first exploration phase of the
agreement. As a result, the NRA collected on the letter of credit in August
2000.
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 also entered into employment agreements with three individuals, which
provide for certain severance payments in the event of a change of control of
our company and subsequent termination by the employees for good reason.
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 9).
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 separate building
for approximately $76,000 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 $50,000 per month.
Our aggregate rental commitments for non-cancellable agreements at December 31,
2000 are as follows (in thousands):
MINIMUM LEASE SUBLEASE
COMMITMENTS INCOME
----------- ------
2001................................................ $ 1,661 $ 978
2002................................................ 1,400 1,005
2003................................................ 1,435 1,032
2004................................................ 1,449 849
2005................................................ 1,074 -
Thereafter.......................................... 9,284 -
----------- -----------
$ 16,303 $ 3,864
=========== ===========
Rental expense was $2.2 million, $2.5 million and $2.0 million for the years
ended December 31, 2000, 1999 and 1998, respectively. Sublease income was $1.1
million, $1.0 million and $0.3 million for the years ended December 31, 2000,
1999 and 1998, respectively.
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. Any compensation from
PDVSA related to this matter will be recorded in the period in which PDVSA
confirms our claim.
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NOTE 5 - TAXES
TAXES OTHER THAN ON INCOME
Benton-Vinccler pays a municipal tax of approximately 2.6 percent on operating
fee revenues it receives for production from the South Monagas Unit. The
components of taxes other than on income were (in thousands):
2000 1999 1998
---- ---- ----
Venezuelan municipal taxes ............................... $3,164 $2,303 $2,109
Severance and production taxes ........................... 28 - -
Franchise taxes .......................................... 131 139 151
Payroll and other taxes .................................. 1,067 1,371 1,417
------ ------ ------
$4,390 $3,813 $3,677
====== ====== ======
TAXES ON INCOME
The tax effects of significant items comprising our net deferred income taxes as
of December 31, 2000 and 1999 are as follows (in thousands):
2000 1999
---- ----
Deferred tax assets:
Operating loss carryforwards ........................................... $ 37,142 $ 36,242
Difference in basis of property ........................................ 4,948 13,040
Other .................................................................. 16,410 14,817
Valuation allowance .................................................... (54,207) (51,913)
-------- --------
Net deferred tax asset ..................................................... $ 4,293 $ 12,186
======== ========
The valuation allowance increased by $1.0 million and decreased by $8.1 million
as a result of the increase in the U.S. deferred tax assets related to the net
operating loss carryforward and to property, respectively. We have determined
that it is more likely than not that these U.S. deferred tax assets will not be
realized.
The components of income before income taxes, minority interest and
extraordinary items are as follows (in thousands):
2000 1999 1998
---- ---- ----
Income (loss) before income taxes
United States ................................................ $(13,033) $(38,637) $ (50,637)
Foreign ...................................................... 51,463 (236) (180,749)
-------- -------- ---------
Total ..................................................... $ 38,430 $(38,873) $(231,386)
======== ======== =========
The provision (benefit) for income taxes consisted of the following at December
31, (in thousands):
2000 1999 1998
---- ---- ----
Current:
United States ...................................................... $ 215 $ (2,216) $ 1,470
Foreign ............................................................ 5,925 3,900 1,406
-------- -------- ---------
6,140 1,684 2,876
-------- -------- ---------
Deferred:
United States ...................................................... - - 3,573
Foreign ............................................................ 7,892 (9,210) (31,360)
-------- -------- ---------
7,892 (9,210) (27,787)
-------- -------- ---------
$ 14,032 $ (7,526) $ (24,911)
======== ======== =========
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A comparison of the income tax expense (benefit) at the federal statutory rate
to our provision for income taxes is as follows (in thousands):
2000 1999 1998
---- ---- ----
Computed tax expense at the statutory rate ................... $ 13,451 $(13,606) $(80,985)
State income taxes, net of federal effect .................... (343) (307) 112
Effect of foreign source income and rate differentials on
foreign income ............................................ (1,826) 4,507 23,987
Change in valuation allowance ................................ 2,294 5,951 32,121
Prior year adjustments ....................................... 1,637 (847) (1,917)
Effect of tax law changes .................................... - (2,220) -
All other .................................................... 679 - -
-------- -------- --------
Sub-total income tax expense (benefit) ....................... 15,892 (6,522) (26,682)
Effects of recording equity income of certain affiliated
Companies on an after-tax basis ........................... (1,860) (1,004) 1,771
-------- -------- --------
Total income tax expense (benefit) ........................... $ 14,032 $ (7,526) $(24,911)
======== ======== ========
Rate differentials for foreign income result from tax rates different from the
U.S. tax rate being applied in foreign jurisdictions and from the effect of
foreign currency devaluation in foreign subsidiaries which use the U.S. dollar
as their functional currency. The effect of tax law changes relates to benefits
from the Venezuela-United States tax treaty ratified in 1999.
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.
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.
NOTE 6 - STOCK OPTION AND STOCK PURCHASE PLANS
During 1989, we adopted our 1989 Nonstatutory Stock Option Plan covering
2,000,000 shares of common stock which were granted to key employees, directors,
independent contractors and consultants at prices equal to or below market
prices, exercisable over various periods. The plan was amended during 1990 to
add 1,960,000 shares of common stock.
In September 1991, we adopted the 1991-1992 Stock Option Plan and the Directors'
Stock Option Plan. The 1991-1992 Stock Option Plan, as amended in 1996 and 1997,
permitted the granting of stock options to purchase up to 4,800,000 shares of
the Company's common stock in the form of ISOs and NQSOs to our officers and
employees of the Company. Options could be granted as ISOs, NQSOs or a
combination of each, with exercise prices not less than the fair market value of
the common stock on the date of the grant. The amount of ISOs that may be
granted to any one participant is subject to the dollar limitations imposed by
the Internal Revenue Code of 1986, as amended. In the event of a change in
control of our company, all outstanding options become immediately exercisable
to the extent permitted by the 1991-1992 Stock Option Plan. All options granted
to date under the plan vest ratably over a three-year period from their dates of
grant and expire ten years from grant date or one year after retirement, if
earlier. Subsequent to shareholder approval of the 1998 Stock-Based Incentive
Plan discussed below, our Board of Directors terminated future grants under the
1991-1992 Stock Option Plan.
The Directors' Stock Option Plan permitted the granting of nonqualified stock
options ("Director NQSOs") to purchase up to 400,000 shares of common stock to
our nonemployee directors. Upon election as a director and annually thereafter,
each individual who served as a nonemployee director was automatically granted
an option to purchase 10,000 shares of common stock at a price not less than the
fair market value of common stock on the date of grant. All Director NQSOs
vested automatically on the date of the grant of the options, and at December
31, 2000, options to purchase 310,000 shares of common stock were both
outstanding and exercisable. The Director stock option plan has been replaced
with the Non-Employee Director Stock Purchase Plan. No additional Director
NQSO's will be granted under the Directors Stock Option Plan.
In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the
"Stock Purchase Plan") to encourage our directors to acquire a greater
proprietary interest in our company through the ownership of our common stock.
Each non-employee director may elect once each year, prior to January 1, to be
effective for the following year and until a new election is made, to receive
shares of our common
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stock for all or a portion of their fee for serving as a director. The number of
shares issuable will be equal to 1.5 times the amount of cash compensation due
the director divided by the fair market value of the common stock on the
scheduled date of payment of the applicable director's fee. The shares will have
a restriction upon their sale for one year from the date of issuance.
In June 1998, our shareholders approved the adoption of the 1998 Stock-Based
Incentive Plan. The 1998 Stock-Based Incentive Plan authorizes up to 1,400,000
shares of our common stock for grants of NQSOs and ISOs, stock appreciation
rights, restricted stock awards and bonus stock awards to our employees or
employees of our subsidiaries or associated companies. The exercise price of
stock options granted under the plan must be no less than the fair market value
of our common stock on the date of grant. The total number of shares for which
awards may be made to any one participant during any calendar year cannot exceed
500,000 shares, as adjusted for any changes in capitalization, such as stock
splits. In the event of a change in control of our company, all outstanding
options become immediately exercisable to the extent permitted by the plan. All
options granted to date under the 1998 Stock-Based Incentive Plan vest ratably
over a three-year period from their dates of grant and expire ten years from
grant date or one year after retirement, if earlier.
In November 1999, we adopted the 1999 Stock Option Plan. The 1999 Stock Option
Plan permits the granting of stock options to purchase up to 2,500,000 shares
of our common stock in the form of ISOs and NQSOs to directors, employees and
consultants. Options may be granted as ISOs, NQSOs or a combination of each,
with exercise prices not less than the fair market value of the common stock on
the date of the grant. The amount of ISOs that may be granted to any one
participant is subject to the dollar limitations imposed by the Internal
Revenue Code of 1986, as amended. In the event of a change in control of our
company, all outstanding options become immediately exercisable to the extent
permitted by the plan. All options granted to date to employees under the 1999
Stock Option Plan vest 50 percent after the first year and 25 percent after
each of the following two years from their dates of grant and expire ten years
from grant date or three months after retirement, if earlier. All options
granted to outside directors and consultants under the 1999 Stock Option Plan
vest ratably over a three-year period from their dates of grant and expire ten
years from grant date.
A summary of the status of our stock option plans as of December 31, 2000, 1999
and 1998 and changes during the years ending on those dates is presented below
(shares in thousands):
2000 1999 1998
---- ---- ----
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
PRICE SHARES PRICE SHARES PRICE SHARES
----- ------ ----- ------ ----- ------
Outstanding at beginning of the year:......... $ 7.55 6,300 $ 11.27 3,712 $ 11.78 3,563
Options granted............................... 2.06 240 2.37 2,701 8.62 513
Options exercised............................. 2.53 (85) - - 7.77 (81)
Options cancelled............................. 4.90 (795) 6.10 (113) 13.88 (283)
-------- -------- -------
Outstanding at end of the year................ 7.74 5,660 7.55 6,300 11.27 3,712
======== ======== =======
Exercisable at end of the year................ 9.68 4,099 11.23 3,251 10.63 2,648
======== ======== =======
Significant option groups outstanding at December 31, 2000 and related weighted
average price and life information follow (shares in thousands):
RANGE OF NUMBER WEIGHTED-AVERAGE NUMBER
EXERCISE OUTSTANDING AT REMAINING WEIGHTED-AVERAGE EXERCISABLE AT WEIGHTED-AVERAGE
PRICES DECEMBER 31, 2000 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 2000 EXERCISE PRICE
------ ----------------- ---------------- -------------- ----------------- --------------
$ 1.88-2.75 2,546 8.7 Years $2.33 1,083 $ 2.31
4.89-7.00 409 3.8 Years 6.19 401 6.19
7.25-11.00 1,093 3.6 Years 8.87 1,003 8.88
11.50-16.50 1,081 5.9 Years 13.59 1,081 13.59
17.38-24.13 531 6.1 Years 20.90 531 20.90
---------- -------
5,660 4,099
========== =======
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The weighted average fair value of the stock options granted from the 1988
Stock-Based Incentive Plan, 1991-1992, 1998 and 1999 Stock Option Plans and the
Directors' Stock Option Plan during 2000, 1999 and 1998 was $1.65, $1.88 and
$6.30 respectively. The fair value of each stock option grant is estimated on
the date of grant using the Black-Scholes option pricing model with the
following weighted average assumptions used:
2000 1999 1998
---- ---- ----
Expected life....................................... 9.1 years 9.3 years 9.1 years
Risk-free interest rate............................. 6.1% 5.9% 5.5%
Volatility.......................................... 74% 73% 62%
Dividend Yield...................................... 0% 0% 0%
We account for stock-based compensation in accordance with Accounting Principles
Board Opinion No. 25 and related interpretations, under which no compensation
cost has been recognized for stock option awards. Had compensation cost for the
plans been determined consistent with SFAS 123, our pro forma net income and
earnings per share for 2000, 1999 and 1998 would have been as follows (in
thousands, except per share data):
2000 1999 1998
---- ---- ----
Net income (loss)...................................... $ 16,224 $ (38,441) $ (190,581)
======== ========== ==========
Net income (loss) per common share:
Basic............................................... $ 0.53 $ (1.30) $ (6.45)
======== ========== ==========
Diluted............................................. $ 0.53 $ (1.30) $ (6.45)
======== ========== ==========
In connection with our acquisition of Benton Offshore China Company in December
1996, we adopted the Benton Offshore China Company 1996 Stock Option Plan. Under
the plan, Benton Offshore China Company is authorized to issue up to 107,571
options to purchase our common stock for $7.00 per share. The plan was adopted
in substitution of Benton Offshore China Company's stock option plan, and all
options to purchase shares of Benton Offshore China Company common stock were
replaced under the plan by options to purchase shares of our common stock. All
options were issued upon the acquisition of Benton Offshore China Company and
vested upon issuance. At December 31, 2000, options to purchase 74,427 shares of
common stock were both outstanding and exercisable.
In addition to options issued pursuant to the plans, options have been issued to
individuals other than officers, directors or employees of the Company at prices
ranging from $10.88 to $11.88 which vest over three to four years. At December
31, 2000, a total of 208,500 options issued outside of the plans were both
outstanding and exercisable. Our expenses associated with these options were not
material.
NOTE 7 - STOCK WARRANTS
During the years ended December 31, 1996, 1995 and 1994, we issued a total of
587,783, 125,000 and 450,000 warrants, respectively. Each warrant entitles the
holder to purchase one share of common stock at the exercise price of the
warrant. Substantially all the warrants are immediately exercisable upon
issuance.
In January 1996, 587,783 warrants were issued in connection with an exchange
offer under which we acquired the outstanding limited partnership interests in
three limited partnerships we sponsored. During the years ended December 31,
1997 and 1996, 1,578 and 9,215, respectively, of the warrants were exercised. In
November 1998, 1999 and again in December 2000, we extended by one year the
expiration date of these warrants, which now will expire on January 18, 2002. We
recorded $135,000, $24,000, and $12,000 of expense in 1998, 1999 and 2000,
respectively, as a result of these warrant extensions.
In June 1995, 125,000 warrants were issued in connection with the issuance of
$20 million of senior unsecured notes.
In July 1994, we issued warrants entitling the holder to purchase a total of
150,000 shares of common stock at $7.50 per share, subject to adjustment in
certain circumstances that are exercisable on or before July 2004, 50,000
warrants were immediately exercisable, and 50,000 warrants became exercisable
each July in 1995 and 1996. During the year ended December 31, 1996, 142,000 of
these warrants were exercised. In September 1994, 250,000 warrants were issued
in connection with the issuance of $15 million of senior unsecured notes, and in
December 1994, 50,000 warrants were issued in connection with a revolving
secured credit facility.
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The dates the warrants were issued, the expiration dates, the exercise prices
and the number of warrants issued and outstanding at December 31, 2000 were
(shares in thousands):
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING
----------- --------------- -------------- ------ -----------
July 1994 July 2004 $ 7.50 150 8
September 1994 September 2002 9.00 250 250
December 1994 December 2004 12.00 50 50
June 1995 June 2007 17.09 125 125
January 1996 January 2002 11.00 588 577
------- --------
1,163 1,010
======= ========
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NOTE 8 - OPERATING SEGMENTS
We regularly allocate resources to and assesses 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 Russia operating segments are derived primarily from the
production and sale of oil. Other income from USA and other is derived primarily
from interest earnings on various investments and consulting revenues.
Operations included under the heading "USA and Other" include corporate
management, exploration activities, cash management and financing activities
performed in the United States and other countries which do not meet the
requirements for separate disclosure. All intersegment revenues, other income
and equity earnings, 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.
YEAR ENDED DECEMBER 31, 2000:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
--------- ------------- -------- ------------- ------------
Revenues
Oil and natural gas sales .......................... $ 139,890 $ 394 $ - $ - $ 140,284
--------- --------- -------- --------- ---------
139,890 394 - - 140,284
--------- --------- -------- --------- ---------
Expenses
Operating expenses ................................. 46,727 59 644 - 47,430
Depletion, depreciation and amortization ........... 16,285 879 11 - 17,175
General and administrative ......................... 3,659 12,014 1,066 - 16,739
Taxes other than on income ......................... 3,355 1,048 (13) - 4,390
--------- --------- -------- --------- ---------
Total expenses ............................... 70,026 14,000 1,708 - 85,734
--------- --------- -------- --------- ---------
Income (loss) from operations .......................... 69,864 (13,606) (1,708) - 54,550
Other non-operating income (expense):
Investment earnings and other ...................... 1,392 8,986 - (1,819) 8,559
Interest expense ................................... (6,131) (24,661) - 1,819 (28,973)
Net gain on exchange rates ......................... 298 28 - - 326
Intersegment revenues (expenses) ................... (12,226) 12,226 - - -
Equity in income of affiliated companies ........... - - 5,313 - 5,313
--------- --------- -------- --------- ---------
(16,667) (3,421) 5,313 - (14,775)
--------- --------- -------- --------- ---------
Income (loss) before income taxes ...................... 53,197 (17,027) 3,605 - 39,775
Income tax expense ..................................... 14,020 12 - - 14,032
--------- --------- -------- --------- ---------
Operating segment income (loss) ........................ 39,177 (17,039) 3,605 - 25,743
Write-down of oil and gas properties and impairments ... - (1,346) - - (1,346)
Minority interest ...................................... (7,869) - - - (7,869)
Extraordinary income on debt repurchase ................ - 3,960 - - 3,960
--------- --------- -------- --------- ---------
Net income (loss) ...................................... $ 31,308 $ (14,425) $ 3,605 $ - $ 20,488
========= ========= ======== ========= =========
Total assets ........................................... $ 166,462 $ 156,780 $ 78,406 $(115,201) $ 286,447
========= ========= ======== ========= =========
YEAR ENDED DECEMBER 31, 1999:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
--------- -------------- -------- ------------ ------------
Revenues
Oil and natural gas sales .......................... $ 89,060 $ - $ - $ - $ 89,060
--------- --------- -------- -------- ---------
89,060 - - - 89,060
--------- --------- -------- -------- ---------
Expenses
Operating expenses ................................. 38,683 34 676 -- 39,393
Depletion, depreciation and amortization ........... 15,705 801 13 - 16,519
General and administrative ......................... 4,482 19,729 1,758 - 25,969
Taxes other than on income ......................... 2,501 1,326 (14) - 3,813
--------- --------- -------- -------- ---------
Total expenses ............................... 61,371 21,890 2,433 - 85,694
--------- --------- -------- -------- ---------
Income (loss) from operations .......................... 27,689 (21,890) (2,433) - 3,366
Other non-operating income (expense)
Investment earnings and other ...................... 758 9,510 2 (1,284) 8,986
Interest expense ................................... (6,834) (23,697) - 1,284 (29,247)
Net gain on exchange rates ......................... 1,033 11 - - 1,044
Intersegment revenues (expenses) ................... (8,906) 8,906 - - -
Equity in income of affiliated companies ........... - - 2,869 - 2,869
--------- --------- -------- -------- ---------
(13,949) (5,270) 2,871 - (16,348)
--------- --------- -------- -------- ---------
Income (loss) before income taxes ...................... 13,740 (27,160) 438 - (12,982)
Income tax expense (benefit) ........................... (7,554) (170) 198 - (7,526)
--------- --------- -------- -------- ---------
Operating segment income (loss) ........................ 21,294 (26,990) 240 - (5,456)
Write-down of oil and gas properties and impairments ... - (25,891) - - (25,891)
Minority interest ...................................... (937) - - - (937)
--------- --------- -------- -------- ---------
Net income (loss) ...................................... $ 20,357 $ (52,881) $ 240 $ - $ (32,284)
========= ========= ======== ======== =========
Total assets ........................................... $ 124,942 $ 188,000 $ 61,989 $(98,620) $ 276,311
========= ========= ======== ======== =========
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YEAR ENDED DECEMBER 31, 1998:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
--------- ------------- --------- ------------ ------------
Revenues
Oil and natural gas sales ........................ $ 82,215 $ (3) $ - $ - $ 82,212
--------- --------- --------- --------- ---------
82,215 (3) - - 82,212
--------- --------- --------- --------- ---------
Expenses
Operating expenses ............................... 38,905 (20) 1,181 - 40,066
Depletion, depreciation and amortization ......... 32,532 625 - - 33,157
General and administrative ....................... 4,505 16,662 318 - 21,485
Taxes other than on income ....................... 2,315 1,362 - - 3,677
--------- --------- --------- --------- ---------
Total expenses ............................. 78,257 18,629 1,499 - 98,385
--------- --------- --------- --------- ---------
Income (loss) from operations ........................ 3,958 (18,632) (1,499) - (16,173)
Other non-operating income (expense)
Investment earnings and other .................... 806 14,014 67 (905) 13,982
Interest expense ................................. (7,261) (25,651) - 905 (32,007)
Net gain on exchange rates ....................... 1,741 26 - - 1,767
Intersegment revenues (expenses) ................. (8,211) 8,211 - - -
Equity in loss of affiliated companies ........... - - (5,062) - (5,062)
--------- --------- --------- --------- ---------
(12,925) (3,400) (4,995) - (21,320)
--------- --------- --------- --------- ---------
Loss before income taxes ............................. (8,967) (22,032) (6,494) - (37,493)
Income tax expense (benefit) ......................... (29,955) 5,044 - - (24,911)
--------- --------- --------- --------- ---------
Operating segment income (loss) ...................... 20,988 (27,076) (6,494) - (12,582)
Write-down of oil and gas properties and impairments . (187,811) (6,082) - - (193,893)
Minority interest .................................... 22,895 - - - 22,895
--------- --------- --------- --------- ---------
Net loss ............................................. $(143,928) $ (33,158) $ (6,494) $ - $(183,580)
========= ========= ========= ========= =========
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NOTE 9 - RUSSIAN OPERATIONS
GEOILBENT, LTD.
We own 34 percent of Geoilbent, Ltd., a Russian limited liability company formed
in 1991 to develop, produce and market crude oil from the North Gubkinskoye
Field in the West Siberia region of Russia. Geoilbent also holds rights to three
additional license blocks. Our investment in Geoilbent is accounted for using
the equity method. Sales quantities attributable to Geoilbent for the years
ended December 31, 2000, 1999 and 1998 were 4,247,590 Bbls, 4,267,647 Bbls and
2,716,476 Bbls, respectively. Prices for crude oil for the years ended December
31, 2000, 1999 and 1998 averaged $17.45, $7.68 and $8.72 per barrel,
respectively. Depletion expense attributable to Geoilbent for the years ended
December 31, 2000, 1999 and 1998 was $2.29, $2.27 and $3.69 per barrel,
respectively. Summarized financial information for Geoilbent follows (in
thousands). All amounts represent 100 percent of Geoilbent.
YEAR ENDED SEPTEMBER 30: 2000 1999 1998
---- ---- ----
Revenues
Oil sales.................................................... $ 74,123 $ 32,770 $ 23,703
----------- ----------- -----------
74,123 32,770 23,703
----------- ----------- -----------
Expenses
Operating expenses........................................... 9,798 4,364 6,863
Depletion, depreciation and amortization..................... 9,557 9,669 10,020
General and administrative................................... 3,407 2,655 3,326
Taxes other than on income................................... 18,286 8,208 6,210
----------- ----------- -----------
41,048 24,896 26,419
----------- ----------- -----------
Income (loss) from operations.................................... 33,075 7,874 (2,716)
Other non-operating income (expense)
Investment earnings and other................................ (543) 6,527 18,023
Interest expense............................................. (8,145) (3,572) (2,648)
----------- ----------- -----------
(8,688) 2,955 15,375
----------- ----------- -----------
Income before income taxes....................................... 24,387 10,829 12,659
Income tax expense............................................... 6,321 1,333 562
----------- ----------- -----------
Net income ...................................................... $ 18,066 $ 9,496 $ 12,097
=========== =========== ===========
2000 1999 1998
---- ---- ----
AT SEPTEMBER 30:
Current assets................................................... $ 30,070 $ 25,699 $ 7,876
Other assets..................................................... 163,219 139,488 129,037
Current liabilities.............................................. 32,700 10,276 15,772
Other liabilities................................................ 41,866 54,254 33,999
Net equity....................................................... 118,723 100,657 87,142
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The European Bank for Reconstruction and Development ("EBRD") and International
Moscow Bank ("IMB") together have agreed to lend up to $65 million to Geoilbent,
based on achieving certain reserve and production milestones, under parallel
reserve-based loan agreements. Under these loan agreements, we and other
shareholders of Geoilbent have significant management and business support
obligations. Each shareholder is jointly and severally liable to EBRD and IMB
for any losses, damages, liabilities, costs, expenses and other amounts suffered
or sustained arising out of any breach by any shareholder of its support
obligations. The loans bear an average interest rate of 15 percent payable on
January 27 and July 27 each year. Principal payments will be due in varying
installments on the semiannual interest payment dates beginning January 27, 2001
and ending by July 27, 2004. The loan agreements require that Geoilbent meet
certain financial ratios and covenants, including a minimum current ratio, and
provides for certain limitations on liens, additional indebtedness, certain
investment and capital expenditures, dividends, mergers and sales of assets.
Geoilbent began borrowing under these facilities in October 1997 and had
borrowed a total of $48.5 million through September 30, 2000. The proceeds from
the loans were used by Geoilbent to develop the North Gubkinskoye and
Prisklonovoye Fields in West Siberia, Russia. The principal payment requirements
for the long-term debt of Geoilbent at September 30, 2000 are as follows for the
years ending September 30 (in thousands):
2001................................................ $ 10,455
2002................................................ 16,000
2003................................................ 11,000
2004................................................ 11,000
2005................................................ -
Subsequent Years.................................... -
----------
$ 48,455
==========
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, with the
agreement of EBRD, Geoilbent ratified an agreement to reimburse us for $2.6
million of such costs, which were included in accounts receivable. However, due
to Geoilbent's need for oil and natural gas investment and the declining prices
for crude oil, in the second quarter of 1998, we agreed to defer payment of
those reimbursements. We received the $2.6 million during 2000.
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. The credit facility is renewable annually. Loans outstanding under
the credit facility bear interest at either LIBOR plus 0.75 percent, subject to
certain adjustments, or the Morgan Guaranty prime rate plus 2 percent, whichever
is selected at the time a loan is made. In conjunction with Geoilbent's
reserve-based loan agreements with EBRD and IMB, repayment of the credit
facility was subordinated to payments due to EBRD and IMB and, accordingly, the
credit facility was reclassified from current to long-term in 1998. The credit
facility contains no restrictive covenants and no financial ratio covenants. At
December 31, 2000, $3.2 million was outstanding under the credit facility.
Excise, pipeline and other tariffs and taxes continue to be levied on all oil
producers and certain exporters, including an oil export tariff that increased
to 34 Euros per ton (approximately $3.80 per barrel) on November 3, 2000 from 15
Euros per ton in 1999. 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, formerly Severneftegaz. Arctic Gas owns the exclusive rights
to evaluate, develop and produce the natural gas, condensate and oil reserves in
the Samburg and Yevo-Yakha license blocks in West Siberia. The two blocks
comprise 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 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 December 31, 2000, we
had loaned $22.0 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 9 percent equity interest.
From December 1998 through November 2000, we purchased shares representing an
additional 20 percent equity interest not subject to any sale or transfer
restrictions. We owned a total of 60 percent of the outstanding voting shares of
Arctic Gas as of December 31, 2000, of which approximately 29 percent were not
subject to any restrictions.
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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 $0.7 million and $0.4
million for the years ended September 30, 2000 and 1999, respectively. Our
weighted-average equity interest, not subject to any sale or transfer
restrictions for the years ended December 31, 2000 and 1999 was 24 percent and
12 percent, respectively. 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.
Arctic Gas began selling oil in June 2000. Summarized financial information for
Arctic Gas follows (in thousands). All amounts represent 100 percent of Arctic
Gas.
YEAR ENDED SEPTEMBER 30: 2000 1999
---- ----
Revenues
Oil Sales................................. $ 3,354 $ -
----------- -----------
3,354 -
----------- -----------
Expenses
Operating expense......................... 1,004 -
Depletion, depreciation and amortization.. 432 85
General and administrative................ 2,154 2,941
Taxes other than on income................ 1,422 64
----------- -----------
5,012 3,090
----------- -----------
Loss from operations......................... (1,658) (3,090)
Other non-operating income (expense)
Other income (expense).................... (14) 585
Interest expense.......................... (1,558) (868)
----------- -----------
(1,572) (283)
----------- -----------
Loss before income taxes..................... (3,230) (3,373)
Income tax expense........................... 188 -
----------- -----------
Net loss..................................... $ (3,418) $ (3,373)
=========== ===========
AT SEPTEMBER 30: 2000 1999
---- ----
Current assets............................... 1,205 1,513
Other assets................................. 10,120 5,043
Current liabilities.......................... 23,955 18,068
Other liabilities............................ - -
Net equity................................... (12,630) (11,512)
NOTE 10 - 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
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, 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 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.
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In August 1999, Benton-Vinccler sold its recently-constructed power generation
facility located in the Uracoa Field of the South Monagas Unit in Venezuela for
$15.1 million. Concurrently with the sale, Benton-Vinccler entered into a
long-term power purchase agreement with the purchaser of the facility to provide
for the electrical needs of the field throughout the remaining term of the
operating service agreement. Benton-Vinccler used the proceeds from the sale to
repay indebtedness that was collateralized by a time deposit made by us.
Permanent repayment of a portion of the loan allowed us to reduce the cash
collateral for the loan thereby making the cash available for working capital
needs.
In December 1999, we and Benton-Vinccler 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 wells have been drilled under the alliance program.
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 completing an 839 square kilometer seismic survey and
drilling three wells to the depths of 12,000 to 18,000 feet within five years.
At the time the block was tendered for international bidding, PDVSA estimated
that this minimum exploration work program would cost $60 million and required
that 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 have a 30 percent interest in the exploration venture, with
Burlington and Anadarko each owning a 35 percent interest. Under the terms of
the operating agreement, which establishes the management company of the
project, Burlington is the operator of the field and, therefore, we are not able
to exercise control of the operations of the venture. Corporacion Venezolana del
Petroleo, S.A., an affiliate of PDVSA, has the right to obtain a 35 percent
interest in the management company, which dilutes the voting power of the
partners on a pro rata basis. In July 1996, formal agreements were finalized and
executed, and 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). As of December 31, 1998, our share of
expenditures was $8.2 million, which was included in the Venezuela cost center
after evaluation for proved reserves, and the standby letter of credit had been
reduced to $11.2 million. During 1999, the Block's first exploration well, the
Jarina 1-X, penetrated a thick potential reservoir sequence, but encountered no
hydrocarbons. As of December 31, 2000, our share of the total expenditures was
$15.4 million. 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, in January 2001, we included $7.7 million of restricted cash that
collateralized the letter of credit in the Venezuelan full cost pool. While the
Venezuela cost center experienced a full cost ceiling test write-down of $187.8
million in 1998, there have been no further impairments.
NOTE 11 - 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 natural gas prospects both onshore and in the state waters of the Gulf
Coast states of Texas, Louisiana and Mississippi. Under the agreements,
Coastline will 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 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
Bbls 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 cash and a 5 percent
carried working interest in up to four wells that may be drilled in the future.
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
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capitalized costs associated with the California Leases of $9.2 million and the
joint interest receivable of $3.1 million due from Molino Energy at December 31,
1999.
NOTE 12 - 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 will, as our wholly owned subsidiary, continue as the
operator and contractor of WAB-21. Benton Offshore China Company has submitted
an exploration program and budget to CNOOC. However, due to certain territorial
disputes over the sovereignty of the contract area, it is unclear when such
program will commence.
In October 1997, we signed a farmout agreement with Shell Exploration (China)
Limited ("Shell") whereby we acquired a 50 percent participation interest in
Shell's Liaohe area onshore exploration project in northeast China. Shell held a
petroleum contract with China National Petroleum Corporation ("CNPC") to explore
and develop the deep rights in the Qingshui Block, approximately 140,000 acres
(563 square kilometers), in the delta of the Liaohe River. Shell was the
operator of the project. In July 1998, we paid to Shell 50 percent of Shell's
prior investment in the Block, which was approximately $4 million ($2 million to
us). Pursuant to the farmout agreement, we were required to pay 100 percent of
the first $8 million of the costs for the phase one exploration period, after
which any development costs were to be shared equally. During the first six
months of 1999, the first exploratory well on the Qingshui Block was drilled to
a total depth of 4,500 meters, and two reservoirs, the Sha-2 and Sha-3, were
tested. Although hydrocarbons were encountered during drilling of the Qing Deep
22, we and operator Shell concluded that the well was non-commercial. As a
result, we elected not to continue to the second exploration phase and have
relinquished our interest in the Block. Accordingly, we recognized a write-down
of the capitalized cost related to the farmout agreement of $12.6 million in the
third quarter of 1999.
NOTE 13 - JORDAN OPERATIONS
In August 1997, we acquired the rights to an Exploration and Production Sharing
Agreement ("PSA") with Jordan's Natural Resources Authority ("NRA") to explore,
develop and produce the Sirhan Block in southeastern Jordan. Under the terms of
the PSA, we were obligated to make certain capital and operating expenditures in
up to three phases over eight years. We were obligated to spend $5.1 million in
the first exploration phase, which was extended to May 2000, for which we posted
a $1 million standby letter of credit, collateralized in full by a time deposit.
During the first quarter of 1998, we reentered two wells and tested two
different reservoirs. The WS-9 well tested significant, but non-commercial
amounts of natural gas; the WS-10 well resulted in no commercial amounts of
hydrocarbons. Therefore, at December 31, 1998, we wrote down $3.7 million in
capitalized costs incurred to date related to the PSA. During 1999, we incurred
an additional $0.3 million in capitalized costs, which were written off at
December 31, 1999. As of the May 17, 2000 expiration date of the PSA, we had
elected not to complete the first exploration phase of the agreement. As a
result, during the second quarter of 2000, we recorded a liability to the NRA
for the obligation remaining under the PSA resulting in impairment expense of
$1.0 million. The NRA collected on the letter of credit in August 2000.
NOTE 14 - 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 then obtained a security
interest in Mr. Benton's shares of stock, personal real estate and proceeds from
certain contractual and stock option agreements. At December 31, 1998, the $5.5
million owed to 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 ($0.7
million for the period July 1, 1999 to December 31, 2000). Measuring the amount
of the allowances requires judgements and estimates, and the amount eventually
realized may differ from the estimate.
In February 2000, 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 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
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the bankruptcy court in the first half of 2001, we will retain our security
interest in Mr. Benton's 600,000 shares of our stock and in his stock options,
and in a portion of certain proceeds of his Consulting Agreement. Repayment of
our loans to Mr. Benton may be achieved through Mr. Benton's liquidation of
certain real and personal property assets; a phased liquidation of stock in our
company resulting from Mr. Benton's exercise of his stock options; and, if
necessary, from the retained interest in the portion of the Consulting
Agreement's proceeds. The amount that we eventually realize and the timing of
receipt of payments will depend upon the timing and results of the liquidation
of Mr. Benton's assets, including Benton Oil and Gas Company stock.
Under the terms of the Consulting Agreement, Mr. Benton will be paid consulting
fees of $485,000 for 2000, reducing to $322,000 in 2001, $240,000 in 2002, and a
declining consulting fee for the remainder of the term which expires December
31, 2006. Mr. Benton will also be entitled to certain additional incentive
bonuses with respect to cash receipts we receive in connection with the
operations or divestiture of Geoilbent and Arctic Gas. To the extent that Mr.
Benton continues to be a consultant to our company, his unvested stock options
will continue to vest and for a period of twelve (12) months thereafter. Mr.
Benton's consulting services will relate principally to our Russian activities.
From February 2000 through December 31, 2000, we paid to Mr. Benton $419,712
under the Consulting Agreement.
Also during 1997 and 1996, we made loans to Mr. M.B. Wray, our Vice Chairman and
Mr. J. M. Whipkey, our then Chief Financial Officer, each loan bearing interest
at 6 percent and collateralized by a security interest in personal real estate.
On May 11, 1999, Mr. Wray repaid the balance of principal and interest on his
loan and on April 25, 2000, Mr. Whipkey repaid the balance of principal and
interest on his loan.
In addition, loans and other receivables from other employees (including one
former employee) totaled $0.1 million and $0.2 million at December 31, 2000 and
1999, respectively.
NOTE 15 - 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) and denominator (shares) of the basic and diluted earnings per share
computations were (in thousands, except per share amounts):
AMOUNT
INCOME/(LOSS) SHARES PER SHARE
------------ --------- ----------
For the Year Ended December 31, 2000
- ------------------------------------
BASIC EPS
Income before extraordinary item available to common stockholders
and assumed conversions ....................................... $ 16,528 30,724 $ 0.54
========= ========= =========
Effect of Dilutive Securities:
Stock options and warrants ....................................... - 166
--------- ---------
DILUTED EPS
Income before extraordinary item available to common stockholders $ 16,528 30,890 $ 0.53
========= ========= =========
For the Year Ended December 31, 1999
- ------------------------------------
BASIC EPS
Loss available to common stockholders ............................ $ (32,284) 29,577 $ (1.09)
--------- --------- =========
Effect of Dilutive Securities:
Stock options and warrants ....................................... - -
--------- ---------
DILUTED EPS
Loss available to common stockholders and assumed
conversions .................................................... $ (32,284) 29,577 $ (1.09)
========= ========= =========
For the Year Ended December 31, 1998
- ------------------------------------
BASIC EPS
Loss available to common stockholders ............................ $(183,580) 29,554 $ (6.21)
--------- --------- =========
Effect of Dilutive Securities:
Stock options and warrants ....................................... - -
--------- ---------
DILUTED EPS
Income available to common stockholders .......................... $(183,580) 29,554 $ (6.21)
========= ========= =========
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An aggregate of 5.6 million options and warrants were excluded from the earnings
per share calculations because their exercise price exceeded the average share
price during the year ended December 31, 2000. For the years ended December 31,
1999 and 1998 6.2 million and 3.3 million options and warrants, respectively,
were excluded from the earnings per share calculations because they were
anti-dilutive.
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
QUARTER ENDED
-------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- -------- ------------ -----------
(amounts in thousands, except per share data)
YEAR ENDED DECEMBER 31, 2000
Revenues ......................................... $ 31,433 $ 32,111 $ 37,972 $ 38,768
Expenses ......................................... (18,647) (22,357) (22,270) (23,806)
Non-operating income (expense) ................... (5,248) (5,201) (5,017) (4,622)
-------- -------- -------- --------
Income from consolidated companies before
income taxes and minority interests ........... 7,538 4,553 10,685 10,340
Income tax expense ............................... 4,636 3,656 5,018 722
-------- -------- -------- --------
Income before minority interests ................. 2,902 897 5,667 9,618
Minority interests ............................... 1,634 1,336 2,007 2,892
-------- -------- -------- --------
Income (loss) from consolidated companies ........ 1,268 (439) 3,660 6,726
Equity in earnings of affiliated companies ....... 1,727 177 2,213 1,196
-------- -------- -------- --------
Income (loss) before extraordinary income ........ 2,995 (262) 5,873 7,922
Extraordinary income on debt repurchase .......... - - 3,095 865
-------- -------- -------- --------
Net income (loss) ................................ $ 2,995 $ (262) $ 8,968 $ 8,787
======== ======== ======== ========
Net income (loss) per common share:
Basic .................................... $ 0.10 $ (0.01) $ 0.29 $ 0.26
Diluted .................................. $ 0.10 $ (0.01) $ 0.29 $ 0.26
QUARTER ENDED
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- -------- ------------ ------------
(amounts in thousands, except per share data)
YEAR ENDED DECEMBER 31, 1999
Revenues ......................................... $ 16,090 $ 20,351 $ 24,565 $ 28,054
Expenses ......................................... (20,337) (23,318) (32,342) (35,589)
Non-operating income (expense) ................... (4,638) (4,571) (4,909) (5,099)
-------- -------- -------- --------
Loss from consolidated companies before
income taxes and minority interests ........... (8,885) (7,538) (12,686) (12,634)
Income tax expense (benefit) ..................... 653 306 1,123 (9,608)
-------- -------- -------- --------
Loss before minority interests ................... (9,538) (7,844) (13,809) (3,026)
Minority interests ............................... 155 200 177 404
-------- -------- -------- --------
Loss from consolidated companies ................. (9,693) (8,044) (13,986) (3,430)
Equity in earnings (losses) of
affiliated companies .......................... 1,030 488 (143) 1,494
-------- -------- -------- --------
Net loss ......................................... $ (8,663) $ (7,556) $(14,129) $ (1,936)
======== ======== ======== ========
Net loss per common share:
Basic .................................... $ (0.29) $ (0.26) $ (0.48) $ (0.07)
Diluted .................................. $ (0.29) $ (0.26) $ (0.48) $ (0.07)
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SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
In accordance with Statement of Financial Accounting Standards No. 69,
"Disclosures About Oil and Gas Producing Activities" ("SFAS 69"), this section
provides supplemental information on our oil and natural gas exploration and
production activities. Tables I through III provide historical cost information
pertaining to costs incurred in exploration, property acquisitions and
development; capitalized costs; and results of operations. Tables IV through VI
present information on our estimated proved reserve quantities, standardized
measure of estimated discounted future net cash flows related to proved
reserves, and changes in estimated discounted future net cash flows.
TABLE I - TOTAL COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION
AND DEVELOPMENT ACTIVITIES (IN THOUSANDS):
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
----------------------------------------------- ----------
UNITED STATES
VENEZUELA CHINA AND OTHER SUBTOTAL RUSSIA TOTAL
--------- -------- --------- --------- --------- ---------
YEAR ENDED DECEMBER 31, 2000
Acquisition costs .................................. $ - $ - $ 170 $ 170 $ - $ 170
Development costs .................................. 47,604 - - 47,604 13,887 61,491
Exploration costs .................................. 94 84 2,470 2,648 4,206 6,854
--------- -------- --------- --------- --------- ---------
$ 47,698 $ 84 $ 2,640 $ 50,422 $ 18,093 $ 68,515
========= ======== ========= ========= ========= =========
YEAR ENDED DECEMBER 31, 1999
Development costs .................................. $ 22,361 $ - $ 104 $ 22,465 $ 6,342 $ 28,807
Exploration costs .................................. 261 8,480 1,761 10,502 1,345 11,847
--------- -------- --------- --------- --------- ---------
$ 22,622 $ 8,480 $ 1,865 $ 32,967 $ 7,687 $ 40,654
========= ======== ========= ========= ========= =========
YEAR ENDED DECEMBER 31, 1998
Development costs .................................. $ 75,928 $ - $ 2,105 $ 78,033 $ 13,276 $ 91,309
Exploration costs .................................. 4,230 4,024 7,853 16,107 3,550 19,657
--------- -------- --------- --------- --------- ---------
$ 80,158 $ 4,024 $ 9,958 $ 94,140 $ 16,826 $ 110,966
========= ======== ========= ========= ========= =========
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS):
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
------------------------------------------------ -----------
UNITED STATES
VENEZUELA CHINA AND OTHER SUBTOTAL RUSSIA TOTAL
--------- -------- --------- --------- --------- ---------
DECEMBER 31, 2000
Proved property costs .............................. $ 426,330 $ 12,879 $ 19,362 $ 458,571 $ 85,086 $ 543,657
Costs excluded from amortization ................... - 16,183 451 16,634 6,536 23,170
Oilfield inventories ............................... 15,343 - - 15,343 2,705 18,048
Less accumulated depletion and impairment .......... (339,542) (12,879) (19,090) (371,511) (27,249) (398,760)
--------- -------- --------- --------- --------- ---------
$ 102,131 $ 16,183 $ 723 $ 119,037 $ 67,078 $ 186,115
========= ======== ========= ========= ========= =========
DECEMBER 31, 1999
Proved property costs .............................. $ 378,631 $ 12,870 $ 18,025 $ 409,526 $ 68,526 $ 478,052
Costs excluded from amortization ................... - 16,108 9 16,117 5,004 21,121
Oilfield inventories ............................... 9,806 - - 9,806 2,084 11,890
Less accumulated depletion and impairment .......... (324,211) (12,870) (17,753) (354,834) (24,102) (378,936)
--------- -------- --------- --------- --------- ---------
$ 64,226 $ 16,108 $ 281 $ 80,615 $ 51,512 $ 132,127
========= ======== ========= ========= ========= =========
DECEMBER 31, 1998
Proved property costs .............................. $ 371,369 $ - $ 6,083 $ 377,452 $ 61,520 $ 438,972
Costs excluded from amortization ................... - 20,498 10,415 30,913 4,315 35,228
Oilfield inventories ............................... 7,214 - - 7,214 2,080 9,294
Less accumulated depletion and impairment .......... (309,381) - (6,083) (315,464) (20,857) (336,321)
--------- -------- --------- --------- --------- ---------
$ 69,202 $ 20,498 $ 10,415 $ 100,115 $ 47,058 $ 147,173
========= ======== ========= ========= ========= =========
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TABLE III - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS
PRODUCING ACTIVITIES (IN THOUSANDS):
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
----------------------------------- ----------
UNITED STATES
VENEZUELA AND OTHER SUBTOTAL RUSSIA TOTAL
--------- --------- --------- -------- ---------
YEAR ENDED DECEMBER 31, 2000
Oil sales ......................................................... $ 139,890 $ 394 $ 140,284 $ 26,091 $ 166,375
Expenses:
Operating expenses and taxes other than on income .............. 46,879 731 47,610 10,152 57,762
Depletion ...................................................... 15,331 45 15,376 3,305 18,681
Write-down of oil and gas properties and impairments ........... - 1,346 1,346 - 1,346
Income tax expense ............................................. 20,398 12 20,410 3,275 23,685
--------- -------- --------- -------- ---------
Total expenses ................................................ 82,608 2,134 84,742 16,732 101,474
--------- -------- --------- -------- ---------
Results of operations from oil and natural gas producing activities $ 57,282 $ (1,740) $ 55,542 $ 9,359 $ 64,901
========= ======== ========= ======== =========
YEAR ENDED DECEMBER 31, 1999
Oil sales ......................................................... $ 89,060 $ - $ 89,060 $ 11,006 $ 100,066
Expenses:
Operating expenses and taxes other than on income .............. 38,841 710 39,551 4,139 43,690
Depletion ...................................................... 14,829 - 14,829 3,325 18,154
Write-down of oil and gas properties and impairments ........... - 25,891 25,891 - 25,891
Income tax expense ............................................. 3,812 638 4,450 436 4,886
--------- -------- --------- -------- ---------
Total expenses ............................................. 57,482 27,239 84,721 7,900 92,621
--------- -------- --------- -------- ---------
Results of operations from oil and natural gas producing activities $ 31,578 $(27,239) $ 4,339 $ 3,106 $ 7,445
========= ======== ========= ======== =========
YEAR ENDED DECEMBER 31, 1998
Oil sales ......................................................... $ 82,215 $ (3) $ 82,212 $ 8,059 $ 90,271
Expenses:
Operating expenses and taxes other than on income .............. 39,069 1,161 40,230 4,445 44,675
Depletion ...................................................... 31,843 - 31,843 2,474 34,317
Write-down of oil and gas properties and impairments ........... 187,811 6,082 193,893 10,100 203,993
Income tax benefit ............................................. (26,793) - (26,793) - (26,793)
--------- -------- --------- -------- ---------
Total expenses ............................................. 231,930 7,243 239,173 17,019 256,192
--------- -------- --------- -------- ---------
Results of operations from oil and natural gas producing activities $(149,715) $ (7,246) $(156,961) $ (8,960) $(165,921)
========= ======== ========= ======== =========
Geoilbent (34 percent ownership by us) and Arctic Gas (29 percent, 24 percent
and 10 percent ownership not subject to certain sale and transfer restrictions
at December 31, 2000, 1999 and 1998, respectively), which are accounted for
under the equity method, have been included at their respective ownership
interests in the consolidated financial statements based on a fiscal period
ending September 30 and, accordingly, results of operations for oil and natural
gas producing activities in Russia reflect the years ended September 30, 2000,
1999 and 1998 for Geoilbent and the years ended September 30, 2000 and 1999 for
Arctic Gas.
TABLE IV - QUANTITIES OF OIL AND NATURAL GAS RESERVES
Proved reserves are estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected to
be recovered through existing wells with existing equipment and operating
methods. All Venezuelan reserves are attributable to an operating service
agreement between Benton-Vinccler and PDVSA, under which all mineral rights are
owned by the government of Venezuela.
The Securities and Exchange Commission requires the reserve presentation to be
calculated using year-end prices and costs and assuming a continuation of
existing economic conditions. Proved reserves cannot be measured exactly, and
the estimation of reserves involves judgmental determinations. Reserve estimates
must be reviewed and adjusted periodically to reflect additional information
gained from reservoir performance, new geological and geophysical data and
economic changes. The estimates are based on current technology and economic
conditions, and we consider such estimates to be reasonable and consistent with
current knowledge of the characteristics and extent of production. The estimates
include only those amounts considered to be Proved Reserves and do not include
additional amounts which may result from new discoveries in the future, or from
application of secondary and tertiary recovery processes where facilities are
not in place or for which transportation and/or marketing contracts are not in
place.
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Proved Developed Reserves are reserves which can be expected to be recovered
through existing wells with existing equipment and existing operating methods.
This classification includes: a) proved developed producing reserves which are
reserves expected to be recovered through existing completion intervals now open
for production in existing wells; and b) proved developed nonproducing reserves
which are reserves that exist behind the casing of existing wells which are
expected to be produced in the predictable future, where the cost of making such
oil and natural gas available for production should be relatively small compared
to the cost of a new well.
Any reserves expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing primary recovery methods
are included as Proved Developed Reserves only after testing by a pilot project
or after the operation of an installed program has confirmed through production
response that increased recovery will be achieved.
Proved Undeveloped Reserves are Proved Reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage are limited to those drilling units offsetting productive units, which
are reasonably certain of production when drilled. Estimates of recoverable
reserves for proved undeveloped reserves may be subject to substantial variation
and actual recoveries may vary materially from estimates.
Proved Reserves for other undrilled units are claimed only where it can be
demonstrated with certainty that there is continuity of production from the
existing productive formation. No estimates for Proved Undeveloped Reserves are
attributable to or included in this table for any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated unless proved effective by actual tests in the area and in the same
reservoir.
Changes in previous estimates of proved reserves result from new information
obtained from production history and changes in economic factors.
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The evaluations of the oil and natural gas reserves as of December 31, 2000 were
prepared by Ryder-Scott, independent petroleum engineers. The evaluations of the
oil and natural gas reserves as of December 31, 1999, 1998 and 1997 were audited
by Huddleston & Co., Inc., independent petroleum engineers.
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
---------------------------------------------------- ----------
MINORITY
INTEREST
UNITED IN NET
STATES VENEZUELA VENEZUELA TOTAL RUSSIA TOTAL
------- --------- --------- -------- -------- --------
PROVED RESERVES-CRUDE OIL, CONDENSATE, AND
NATURAL GAS LIQUIDS (MBBLS)
YEAR ENDED DECEMBER 31, 2000
Proved reserves beginning of the year ......... - 134,961 (26,992) 107,969 40,129 148,098
Revisions of previous estimates ............. - (8,826) 1,765 (7,061) (2,811) (9,872)
Purchases of reserves in place .............. 15 - - 15 - 15
Extensions, discoveries and improved recovery - 6,268 (1,254) 5,014 12,610 17,624
Production .................................. (7) (9,364) 1,873 (7,498) (1,493) (8,991)
Sales of reserves in place .................. (8) - - (8) - (8)
------- -------- ------- -------- -------- --------
Proved reserves end of year ................... - 123,039 (24,608) 98,431 48,435 146,866
======= ======== ======= ======== ======== ========
YEAR ENDED DECEMBER 31, 1999
Proved reserves beginning of the year ......... - 137,835 (27,567) 110,268 31,053 141,321
Revisions of previous estimates ............. - (7,488) 1,498 (5,990) (531) (6,521)
Extensions, discoveries and improved recovery - 14,281 (2,856) 11,425 11,058 22,483
Production .................................. - (9,667) 1,933 (7,734) (1,451) (9,185)
------- -------- ------- -------- -------- --------
Proved reserves end of year ................... - 134,961 (26,992) 107,969 40,129 148,098
======= ======== ======= ======== ======== ========
YEAR ENDED DECEMBER 31, 1998
Proved reserves beginning of the year ......... - 94,671 (18,934) 75,737 26,113 101,850
Revisions of previous estimates ............. - 25,119 (5,024) 20,095 (2,283) 17,812
Extensions, discoveries and improved recovery - 30,217 (6,043) 24,174 8,147 32,321
Production .................................. - (12,172) 2,434 (9,738) (924) (10,662)
------- -------- ------- -------- -------- --------
Proved reserves end of year ................... - 137,835 (27,567) 110,268 31,053 141,321
======= ======== ======= ======== ======== ========
PROVED DEVELOPED RESERVES AT:
December 31, 2000 ............................. - 67,217 (13,443) 53,774 17,238 71,012
December 31, 1999 ............................. - 67,119 (13,423) 53,695 15,120 68,815
December 31, 1998 ............................. - 75,636 (15,127) 60,509 9,745 70,254
December 31, 1997 ............................. - 68,868 (13,774) 55,094 5,443 60,537
PROVED RESERVES-NATURL GAS (MMCF)
YEAR ENDED DECEMBER 31, 2000
Proved reserves beginning of the year ......... - - - - - -
Revisions of previous estimates ............. - - - - - -
Purchases of reserves in place .............. - - - - - -
Extensions, discoveries and improved recovery 1,071 - - 1,071 152,496 153,567
Production .................................. (43) - - (43) - (43)
Sales of reserves in place .................. (1,028) - - (1,028) - (1,028)
------- -------- ------- -------- -------- --------
Proved reserves end of the year ............... - - - - 152,496 152,496
======= ======== ======= ======== ======== ========
PROVED DEVELOPED RESERVES AT:
December 31, 2000 ............................. - - - - 17,801 17,801
December 31, 1999 ............................. - - - - - -
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO
PROVED OIL AND NATURAL GAS RESERVE QUANTITIES
The standardized measure of discounted future net cash flows is presented in
accordance with the provisions of SFAS 69. In preparing this data, assumptions
and estimates have been used, and we caution against viewing this information as
a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for
fixed and determinable escalations provided by contract, to the estimated future
production of year-end proved reserves. Future cash inflows were reduced by
estimated future production and development costs to determine pre-tax cash
inflows. Future income taxes were estimated by applying the year-end statutory
tax rates to the future pre-tax cash inflows, less the tax basis of the
properties involved, and adjusted for permanent differences and tax credits and
allowances. The resultant future net cash inflows are discounted using a ten
percent discount rate.
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Geoilbent received a waiver from the export tariff assessed on all oil produced
in and exported from Russia for 1995. In July 1996, such oil export tariffs were
terminated in conjunction with a loan agreement with the International Monetary
Fund, although a new oil export tariff of 15 Euros per ton ($1.97 per Bbl) was
introduced in 1999 and increased to 34 Euros per ton (approximately $3.80 per
Bbl) in 2000. Excise, pipeline and other taxes continue to be levied on all oil
producers and certain exporters. Although the Russian regulatory environment has
become less volatile, we are unable to predict the impact of taxes, duties and
other burdens for the future.
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
----------------------------------------- ----------
MINORITY
INTEREST IN
VENEZUELA VENEZUELA NET TOTAL RUSSIA TOTAL
----------- ------------ ----------- ----------- -----------
(amounts in thousands)
DECEMBER 31, 2000
Future cash inflow ................................ $ 1,505,870 $(301,174) $ 1,204,696 $ 1,273,327 $ 2,478,023
Future production costs ........................... (618,870) 123,774 (495,096) (811,678) (1,306,774)
Future development costs .......................... (166,039) 33,208 (132,831) (70,620) (203,451)
----------- --------- ----------- ----------- -----------
Future net revenue before income taxes ............ 720,961 (144,192) 576,769 391,029 967,798
10% annual discount for estimated timing
of cash flows .................................. (260,381) 52,076 (208,305) (176,352) (384,657)
----------- --------- ----------- ----------- -----------
Discounted future net cash flows before
income taxes ................................... 460,580 (92,116) 368,464 214,677 583,141
Future income taxes, discounted at 10%
per annum ...................................... (104,894) 20,979 (83,915) (43,072) (126,987)
----------- --------- ----------- ----------- -----------
Standardized measure of discounted future
net cash flows ................................. $ 355,686 $ (71,137) $ 284,549 $ 171,605 $ 456,154
=========== ========= =========== =========== ===========
DECEMBER 31, 1999
Future cash inflow ................................ $ 1,727,228 $(345,446) $ 1,381,782 $ 566,201 $ 1,947,983
Future production costs ........................... (543,976) 108,795 (435,181) (150,370) (585,551)
Future development costs .......................... (144,639) 28,928 (115,711) (38,210) (153,921)
----------- --------- ----------- ----------- -----------
Future net revenue before income taxes ............ 1,038,613 (207,723) 830,890 377,621 1,208,511
10% annual discount for estimated timing
of cash flows .................................. (386,930) 77,386 (309,544) (154,032) (463,576)
----------- --------- ----------- ----------- -----------
Discounted future net cash flows before
income taxes ................................... 651,683 (130,337) 521,346 223,589 744,935
Future income taxes, discounted at 10%
per annum ...................................... (175,602) 35,121 (140,481) (47,676) (188,157)
----------- --------- ----------- ----------- -----------
Standardized measure of discounted future
net cash flows ................................. $ 476,081 $ (95,216) $ 380,865 $ 175,913 $ 556,778
=========== ========= =========== =========== ===========
DECEMBER 31, 1998
Future cash inflow ................................ $ 778,765 $(155,753) $ 623,012 $ 183,524 $ 806,536
Future production costs ........................... (527,856) 105,571 (422,285) (70,953) (493,238)
Future development costs .......................... (147,806) 29,561 (118,245) (25,048) (143,293)
----------- --------- ----------- ----------- -----------
Future net revenue before income taxes ............ 103,103 (20,621) 82,482 87,523 170,005
10% annual discount for estimated timing
of cash flows .................................. (40,648) 8,130 (32,518) (37,977) (70,495)
----------- --------- ----------- ----------- -----------
Discounted future net cash flows before
income taxes ................................... 62,455 (12,491) 49,964 49,546 99,510
Future income taxes, discounted at 10%
per annum ...................................... - - - (6,298) (6,298)
----------- --------- ----------- ----------- -----------
Standardized measure of discounted future
net cash flows ................................. $ 62,455 $ (12,491) $ 49,964 $ 43,248 $ 93,212
=========== ========= =========== =========== ===========
S-32
76
76
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
CONSOLIDATED COMPANIES EQUITY AFFILIATES
---------------------------- ---------------------------------
2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
(amounts in thousands)
Present Value at January 1 ....................... $ 380,865 $ 49,964 $ 233,176 $ 175,913 $ 43,248 $ 63,433
Sales of oil and natural gas, net of related costs (58,913) (40,303) (34,513) (20,977) (3,238) (3,614)
Revisions to estimates of proved reserves
Net changes in prices, development and
production costs ............................ (124,402) 552,614 (295,131) (72,740) 120,742 (43,072)
Quantities ..................................... (26,494) (26,671) 11,809 (19,685) (2,858) (3,134)
Sales of reserves in place
Extensions, discoveries and improved recovery,
net of future costs ............................ 16,429 65,184 22,893 73,542 54,326 18,132
Accretion of discount ............................ 52,135 4,996 29,123 22,359 4,955 7,770
Net change in income taxes ....................... 56,567 (140,481) 58,054 4,604 (41,378) 7,965
Development costs incurred ....................... 36,210 28,558 37,832 8,475 4,370 8,311
Changes in timing and other ...................... (47,848) (112,996) (13,279) 114 (4,254) (12,543)
--------- --------- --------- --------- --------- --------
Present Value at December 31 ..................... $ 284,549 $ 380,865 $ 49,964 $ 171,605 $ 175,913 $ 43,248
========= ========= ========= ========= ========= ========
TOTAL
-----
2000 1999 1998
---- ---- ----
Present Value at January 1 ....................... $ 556,778 $ 93,212 $ 296,609
Sales of oil and natural gas, net of related costs (79,890) (43,541) (38,127)
Revisions to estimates of proved reserves
Net changes in prices, development and
production costs ............................ (197,142) 673,356 (338,203)
Quantities ..................................... (46,179) (29,529) 8,675
Sales of reserves in place
Extensions, discoveries and improved recovery,
net of future costs ............................ 89,971 119,510 41,025
Accretion of discount ............................ 74,494 9,951 36,893
Net change in income taxes ....................... 61,171 (181,859) 66,019
Development costs incurred ....................... 44,685 32,928 46,143
Changes in timing and other ...................... (47,734) (117,250) (25,822)
--------- --------- ---------
Present Value at December 31 ..................... $ 456,154 $ 556,778 $ 93,212
========= ========= =========
S-33
77
77
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of
Carpinteria, State of California, on the 30th day of March, 2001.
BENTON OIL AND GAS COMPANY
--------------------------
(Registrant)
Date: March 30, 2001 By:/s/Peter J. Hill
------------------- --------------------------
Peter J. Hill
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed by the following persons on the 30th day of March,
2001, on behalf of the Registrant in the capacities indicated:
Signature Title
--------- -----
/s/Peter J. Hill Director, President and Chief Executive Officer
-----------------------------------
Peter J. Hill
/s/Steven W. Tholen Senior Vice President, Chief Financial
----------------------------------- Officer and Treasurer
Steven W. Tholen
(Principal Financial Officer)
/s/Chris C. Hickok Vice President-Controller
-----------------------------------
Chris C. Hickok
(Principal Accounting Officer)
/s/Michael B. Wray Chairman of the Board and Director
-----------------------------------
Michael B. Wray
/s/Stephen D. Chesebro' Director
-----------------------------------
Stephen D. Chesebro'
/s/John U. Clarke Director
-----------------------------------
John U. Clarke
/s/Byron A. Dunn Director
-----------------------------------
Byron A. Dunn
/s/H.H. Hardee Director
----------------------------------
H.H. Hardee
/s/Patrick M. Murray Director
-----------------------------------
Patrick M. Murray
78
78
SCHEDULE II
BENTON OIL AND GAS COMPANY
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
ADDITIONS
--------------------------
BALANCE AT CHARGED TO DEDUCTIONS BALANCE AT
BEGINNING OF CHARGED TO OTHER FROM END OF
YEAR INCOME ACCOUNTS RESERVES YEAR
------------ ---------- ---------- --------- ----------
AT DECEMBER 31, 2000
Amounts deducted from applicable assets
Accounts receivable $ 6,187 $ 331 - - $ 6,518
Deferred tax asset 51,913 2,446 - 152 54,207
Investment at cost 1,350 - - - 1,350
AT DECEMBER 31, 1999
Amounts deducted from applicable assets
Accounts receivable $ 3,236 $ 858 2,093 - $ 6,187
Deferred tax asset 45,962 14,541 - 8,590 51,913
Investment at cost - 1,350 - - 1,350
Reserves included in stockholders' equity
Allowance for employee note secured by
Benton Oil and Gas Company stock 2,093 - (2,093) - -
AT DECEMBER 31, 1998
Amounts deducted from applicable assets
Accounts receivable $ 367 $ 2,869 - - $ 3,236
Deferred tax asset 13,841 32,121 - - 45,962
Reserves included in stockholders' equity
Allowance for employee note secured by
Benton Oil and Gas Company stock - 2,093 - - 2,093