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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.DC 20549
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FORM 10-K
(Mark One)
[X] ANNUAL REPORT UNDER(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002,
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NO.: 1-10762
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BENTON OIL AND GAS COMPANY
(Exact name of registrant as specified in its charter)HARVEST NATURAL RESOURCES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 77-0196707
(State or other jurisdiction of (IRS(STATE OR OTHER JURISDICTION OF INCORPORATION OR ORGANIZATION) (I.R.S. Employer
incorporation or organization) Identification Number)
15835 PARK TEN PLACE DRIVE, SUITE 115
77084
HOUSTON, TEXAS (Zip Code)
(Address of principal executive offices)77084
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODERegistrant's telephone number, including area code (281) 579-6700
SECURITIES REGISTERED PURSUANT TO SECTIONSecurities registered pursuant to Section 12(b) OF THE ACT:of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Stock, $.01 Par Value NYSE
SECURITIES REGISTERED PURSUANT TO SECTIONSecurities registered pursuant to Section 12(g) OF THE ACT:of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
None None
Indicate by check mark whether the Registrantregistrant (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 Registrantregistrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X]X No
[ ]
On March 25, 2002, the aggregate market value of the shares of voting stock
of Registrant held by non-affiliates was approximately $138,096,369 based on a
closing sales price on NYSE of $4.03.
As of March 25, 2002, 34,267,089 shares of the Registrant's common stock
were outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 2002 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. [ ]
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes X No
----------- ----------
State the aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the price at which the common equity
was last sold, or the average bid and asked price of such common equity as of
the last business day of the registrant's most recently completed second fiscal
quarter, June 28, 2002: $174,945,360.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practical date. Class: Common Stock, par value
$0.01 per share, on March 21, 2003, shares outstanding: 35,216,211.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 2003 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.
BENTON OIL AND GAS COMPANYHARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
PAGEPage
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Part I
Item 1. Business....................................................Business............................................................................... 2
Item 2. Properties.................................................. 24Properties............................................................................. 18
Item 3. Legal Proceedings........................................... 24Proceedings...................................................................... 18
Item 4. Submission of Matters to a Vote of Security Holders......... 25Holders ................................... 18
Part II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters......................................... 25Matters..................................................... 19
Item 6. Selected Consolidated Financial Data........................ 26Data................................................................ 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................... 27Operations................................................. 21
Item 7A. Quantitative and Qualitative Disclosures about
Market Risk........................................................ 44Risk......................................................................... 36
Item 8. Financial Statements and Supplemental Data.................. 45Supplementary Data............................................ 37
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.................................... 46Disclosure ............................................. 37
Part III
Item 10. Directors and Executive Officers of the Registrant.......... 46Registrant .................................... 38
Item 11. Executive Compensation...................................... 46Compensation................................................................. 38
Item 12. Security Ownership of Certain Beneficial
Owners and Management.................................................. 46Management and
Related Stockholder Matters......................................................... 38
Item 13. Certain Relationships and Related Transactions.............. 46Transactions ........................................ 38
Item 14. Controls and Procedures................................................................ 38
Part IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K......................................................... 468-K................................................................. 40
Financial Statements..................................................Statements...................................................................................... S-1
Signatures............................................................ S-40Signatures................................................................................................ S-37
1
PART I
The CompanyHarvest Natural Resources, Inc. ("Harvest" or 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"budget",
"anticipate", "expect", "believes", "goals", "projects", "plans", "anticipates",
"estimates", "should", "could", "assume" and similar expressions are intended to
identify forward-looking statements. In accordance with the provisions of the
Private Securities Litigation Reform Act of 1995, the Company cautionswe caution you that important
factors could cause actual results to differ materially from those in the
forward-looking statements. Such factors include the Company'sour substantial concentration
of operations in Venezuela, and Russia, the political and economic risks associated with
international operations, the anticipated future development costs for the
Company'sour
undeveloped proved reserves, the risk that actual results may vary considerably
from reserve estimates, the dependence upon the abilities and continued
participation of certain of our key employees, of the Company, the risks normally incident to
the operation and development of oil and gas properties and the drilling of oil
and natural gas wells, the availability of materials and supplies necessary to
projects and operations, the price for oil and natural gas and other risks describedrelated financial
derivatives, changes in our filings withinterest rates, basis risk and counterparty credit risk
in executing commodity price risk management activities, the Securities and Exchange
Commission. The following factors, among others, in some cases have affected and
could cause actual results and plans for future periodsCompany's ability
to differ materially
from those expressed or implied in any such forward-looking statements:
fluctuations inacquire oil and natural gas prices,properties that meet its objectives, changes in operating
costs, overall economic conditions, political stability, civil unrest, acts of
terrorism, currency and exchange risks, currency controls, 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.
At the end of Item 1 is a glossary of terms.
ITEM 1.1 BUSINESS
GENERAL
Benton Oil and Gas CompanyHarvest Natural Resources, Inc. is an independent energy corporation which has
beencompany
engaged in the development and production of oil and gas properties since 1989,
when it was incorporated under Delaware law. We have developed significant
interests in the Bolivarian Republic of Venezuela ("Venezuela") and the Russian
Federation ("Russia"), through our equity affiliate, and have acquired certain less significant interests in
other parts of the world.undeveloped acreage
offshore China. Our producing operations are conducted principally through our
80 percent-owned Venezuelan subsidiary, Benton-Vinccler, C.A.
("Benton-Vinccler"), which operates the South Monagas Unit in Venezuela; and
Limited Liability Company Geoilbent Ltd.("Geoilbent"), a Russian
limited liability company of which we
own 34 percent and which operates the North Gubkinskoye and South Tarasovskoye
Fields in West Siberia, Russia. Additionally,
we own 68 percent of the equity interest in Arctic Gas Company, of which 29
percent was subject to restrictions on transfer and 39 percent was not subject
to restrictions on transfer, as of December 31, 2001. Arctic Gas was formed to
explore and develop the Samburg and Yevo-Yakha License Blocks in the West
Siberian Basin of Russia. On February 27, 2002, we entered into a Sale and
Purchase Agreement ("Transaction") to sell our entire 68 percent interest in Arctic Gas Company
("Proposed Arctic Gas Sale"Gas"), to a nominee of the Yukos Oil Company, a Russian oil and gas
company, for $190 million plus approximately $30 million as repayment of
inter-company loans owed to us by Arctic Gas. We have
expanded into other, less significant projectsGas (the "Arctic Gas Sale"). On April
12, 2002, we completed the Arctic Gas Sale and recognized a gain of $144.0
million ($93.6 million after tax). From December 14, 2002 through February 6,
2003, no sales of our Venezuelan oil production were made because of Petroleos
de Venezuela, S.A.'s ("PDVSA") inability to accept our oil due to the national
civil work stoppage in China, California,Venezuela. In restoring production, we encountered
problems with some of our wells, but we do not believe the associated costs will
be material. By the end of March 2003, our average production was approximately
24,000 barrels of oil per day. On February 5, 2003, the Venezuelan government
imposed currency controls. See Item 7 - Management's Discussion and Louisiana.Analysis of
Financial Conditions and Results of Operations for a complete description of
these events.
As of December 31, 2001,2002, we had total estimated proved reserves, net of
minority interest and including our share of 168.8equity affiliates, of 127.3 MMBOE,
and a standardized measure of discounted future net cash flow, before income
taxes, for total proved reserves of $365.7$526.7 million. Of these totals, our
interests in the South Monagas Unit represented 83.6102.5 MMBOE and $481.3 million,
and our equity interest in Geoilbent represented 24.8 MMBbls and $176.2$45.4 million,
Geoilbent represented 29.6 MMBbls and $81.1 million, and Arctic
Gas (based on our 39 percent unrestricted ownership) represented 55.6 MMBOE and
$108.4 million.respectively.
As of December 31, 2001,2002, we had total assets of $348.2$335.2 million. For the
year ended December 31, 2002, we had total revenues of $126.7 million, net cash
provided by operating activities of $42.6 million, and long-term debt of
2
$104.7 million. For the year ended December 31, 2001, we had total revenues of
$122.4 million, net cash flows from operations, before working capital changes,provided by operating activities of $28.2 million,
earnings before interest, income taxes and depletion, depreciation and
amortization ("EBITDA") of $58.0$36.6 million, and
long-term debt of $221.6 million.
ForAVAILABLE INFORMATION
We file annual, quarterly, and current reports, proxy statements, and
other documents with the year ended December 31, 2000,
2
SEC under the Securities Act of 1934. The public may
read and copy any materials that 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.
We currently have significant debt principal obligations payable in 2003
($108 million) and 2007 ($105 million). Our ability to meet our debt obligations
and to reduce our level of debt dependsfile with the SEC at the SEC's Public
Reference Room at 450 Fifth Street, NW, Washington, DC 20549. The public may
obtain information on the implementation of our strategic
objectives, and in particular the Proposed Arctic Gas Sale. On March 22, 2002,
we were notified that the Transaction had received the requisite consents from
the Russian Ministry for Antimonopoly Policy and Support for Entrepreneurship.
On March 28, 2002, we received the first payment ($120.0 million)operation of the Proposed Arctic Gas Sale proceeds.Public Reference Room by calling the
SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains
reports, proxy and information statements, and other information regarding
issuers, including the Company, that file electronically with the SEC. The
public can obtain any documents that we file with SEC at http://www.sec.gov.
We expect that all aspectsalso make available, free of the Transaction
will be completed by April 2002. While we have no assurance that the Transaction
will close, the net proceeds should be sufficient to retire early all ofcharge on or through our 2003 debt service obligation. See The Proposed Arctic Gas Sale if Closed Can
Partially Reduce the Impact of Leverage in Item 7 -- Management's Discussion and
Analysis of Financial Condition and Results of Operations, and Note 16 to the
Audited Financial Statements in Item 14 -- Exhibits, Financial Statement
Schedules andInternet
website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly
Reports on Form 8-K.10-Q, Current Reports on Form 8-K, and if applicable, amendments
to those reports filed or furnished pursuant to Section 13(a) of the Exchange
Act as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the SEC. In the event the Proposed Arctic Gas Sale
does not close, we will evaluate alternatives with respect to our 2003 repayment
obligation. In the meantime, we believe that cash flow from operations,
supplemented by other asset sales or borrowings will be adequate to satisfy
interest payments on outstanding debt. However, general economic conditions and
financial, business and other factors affect our operations and our future
performance. Many of these factors are beyond our control.
MANAGEMENT, OPERATIONAL AND FINANCIAL RESTRICTIONS
We have taken the necessary steps to strengthen management, improve our
operations and enhance our financial flexibility. In 2001, we completed the
following:
- installed new senior management;
- redefined our strategic priorities to focus on value creation;
- initiated capital conservation steps and financial transactions,
including the Proposed Arctic Gas Sale, designed to de-leverageaddition, the Company and improve our cash flow allowing debt retirement and
reinvestment;
- undertookhas adopted a comprehensive studycode of
our core Venezuelan asset which
focused on enhancing the valueethics that applies to all of its production;
- built the Tucupita pipeline in Venezuela to reduce transportation costs;
- soughtemployees, including its chief executive
officer, principal financial officer and received relief from certain restrictive provisions of our
debt instruments;
- reduced our operating expenses, corporate overhead, moved our
headquarters to Houston and transferred engineering, geological and
geophysical activities to our overseas offices; and
- proposed a change in our name to Harvest Natural Resources, Inc.
We continue to explore means by which to maximize stockholder value. On
February 27, 2002, we entered into a Sale and Purchase Agreement ("Transaction")
to sell our entire 68 percent interest in Arctic Gas Company ("Proposed Arctic
Gas Sale") to a nomineeprinciple accounting officer. The text
of the Yukos Oil Company, a Russian oil and gas company,
for $190 million plus approximately $30 million as repaymentcode of inter-company
loans owed to us by Arctic Gas. On March 22, 2002, we were notified thatethics has been posted on the Transaction had received the requisite consents from the Russian Ministry of
Antimonopoly and Support for Entrepreneurship. On March 28, 2002, we received
the first payment ($120.0 million)Governance section of the Proposed Arctic Gas Sale proceeds.
While no assurances can be given, we expect that all aspects of the Transaction
will be completed by April 2002.
The net proceeds expected to be realized from the sale, after expenses,
taxes, and the settling of certain related claims, is estimated to be
approximately $150 million. These funds will be used, in part, to retire early
all of the $108 million of 11 5/8% senior notes, which are due in May 2003, in
accordance with their terms and without penalty. We intend to use any remaining
net proceeds and cash received from the repayment of loans to further reduce
debt from time to time, accelerate our strategic growth in Venezuela and Russia,
and for
3
general corporate purposes. Retirement of all the outstanding 11 5/8% notes
eliminates $12.6 million, or $0.37 per diluted share, of annual interest expense
and should mitigate near-term concern about the Company's
liquidity. These
retirements, plus the gain on sale, will allow us to fulfill our previous
commitment to restore our balance sheet strength by reducing our
debt-to-capitalization ratio from over 77% to the 41% range (see Management's
Discussion and Analysis of Financial Condition and Results of Operations of
Management, Operational and Financial Restrictions).
We possess significant producing properties in Venezuela, which we believe
have yet to be optimized, and valuable unexploited acreage in both Venezuela and
Russia. We believe the eleven new wells drilled in the South Tarasovskoye Field
since July 2001 significantly increase the value of our Geoilbent properties. In
December 2001 and January 2002, we spudded the first two wells in our seven well
Tucupita Field program in Venezuela. We are evaluating the construction of
additional processing and handling facilities and are in discussions with an
affiliate of Petroleos de Venezuela, S.A. ("PDVSA") regarding a sales contract
that may allow for the first-time sale of natural gas in Venezuela by our
affiliate.
In May 2001, we initiated a process intended to effectively extend the
maturity of the senior notes due May 1, 2003 by exchanging new 13.125 percent
senior notes due December 2007 plus warrants to purchase shares of our common
stock for each of the 2003 Notes. The exchange offer was withdrawn in July 2001.
However, in August 2001, we solicited and received the requisite consents from
the holders of both the 2003 Notes and the 2007 Notes to amend certain covenants
in the indentures governing the notes to enable Arctic Gas Company to incur
nonrecourse debt of up to $77 million to fund its oil and gas development
program. As an incentive to consent, we paid each noteholder an amount in cash
equal to $2.50 per $1,000 principal amount of notes held for which executed
consents were received. The total amount of consent fees paid to the consenting
noteholders was $0.3 million, which has been included in 2001 general and
administrative expenses.
In June 2001, we implemented a plan designed to reduce overall general and
administrative costs, including exploration overhead, at our corporate
headquarters and to transfer management oversight of geological and geophysical
activities to our overseas offices in Maturin, Venezuela and in Western Siberia
and Moscow, Russia. The reduction in general and administrative costs was
accomplished by reducing our headquarters staff and relocating our headquarters
to Houston, Texas from Carpinteria, California. For 2001, we recorded
non-recurring items of $11.4 million; $5.7 million of which are included in
general and administrative expenses, $1.7 million of which are included in
depletion, depreciation and amortization, $3.2 million in operating expenses and
$0.8 in taxes other than income. The general and administrative expenses include
$2.2 million on the withdrawn debt exchange, $2.2 million for severance and
termination benefits for 33 employees, $1.1 million for lease relinquishment
expenses and $0.2 million for relocation costs to Houston. Depletion,
depreciation and amortization included $0.9 million for the reduction in the
carrying value of fixed assets that were not transferred to Houston and $0.8
million loss on subleasing the former Carpinteria headquarters. All expenses
were paid or accrued by December 31, 2001. The accrued balance of $0.1 million
will be paid in 2002.website.
OPERATING STRATEGY
Our business strategy supports the steady investment, prudent risk
management and timely harvestdevelopment of our large hydrocarbon resources for attractive
values.resources. For the
foreseeable future, we believe our best success will be found in Venezuela and
Russia, areas in which we have significant experience and expertise. During 2001,Near term,
our operating strategy was necessarilyis focused on improving the efficiency and efficaciesrealization of value from our current
operations in both Venezuela and Russia. Over the years, we have benefited from theInvestments in Venezuela and Russia are
exposed to significant capital
commitment made to these areas, but have suffered financially from sub-optimal
operating, contracting and risk management practices, which, for the most part,
have been or are currently in the process of being significantly improved.political risks.
In Venezuela, we implemented new development andintend to continue to seek cost effective increases in
production plans at Benton-
Vinccler following an eight-month suspension of drilling and an extensive
reservoir study, which resulted in increased production, lower operating costs
and added confidence in our future drilling plans to extend the life and value of our fields. Completing a gas project
in the field.fourth quarter of 2003 within budget is an important part of this
strategy because it creates a new source of revenues from sales of natural gas.
We haveare also streamlined decision making, improved internal
controlslooking for ways to diversify our cash flow as events in Venezuela
demonstrated the benefits of country risk diversification of our cash flow
sources when we lost six weeks of production.
Our Russian operations are an important element of our diversification
strategy. We and implemented
4
industry standard techniques to mitigate geologic, operating, financial and
political risks attendant with doing business in Venezuela.
In Russia, where we are a minoritythe majority share owner in Geoilbent we are attemptingcontinue to pursue a similar course with the help of other interest owners, in orderstrive to
improve operations and extendmonetize the lifevalue of the field, lowerfields by lowering operating
costs and enhanceenhancing financial results. TheseThe Geoilbent assets represent
significant potential value for us, but remain subject to sub-optimal operating
conditions while our lack of majority control over its operations could inhibitinhibits our
ability to implement necessary changes in management, operations or financing
matters.matters to fully realize the potential of Geoilbent's assets. In both Venezuelaaddition, our
financial results have been significantly hampered by low Russian domestic oil
prices while world oil prices have reached multi-year high levels. Geoilbent's
independent accountants have indicated in their report that substantial doubt
exists regarding Geoilbent's ability to meet its debts as they become due and
continue as a going concern. An important part of our near-term strategy is to
establish and implement a plan to maximize the value of our investment in
Geoilbent by improving its operations, achieving a control position or selling
our minority ownership interest.
We believe that Russia has opportunities and that we, as an independent
oil and gas operator, can exploit using Western management and operating
techniques. The overall goal is to add undeveloped or underdeveloped resources
of oil and gas. Through phased investment, we can then increase and capture the
long-term value of the asset. We seek significant, legacy assets, with a
controlling ownership interest in other countries aroundpartnership with local industry partners.
These partners must understand and be familiar with the world, the
development of local markets for natural gas represents a significant
opportunity for us. However, the development of these markets, in large part,
depends upon substantial capital investment by third parties in the
infrastructure needed to produce, gather, treat, transport, storeasset and convert
natural gas into marketable products. While this investment is beginning to
materialize in many of these markets, it will take many years, in some
instances, to place such assets into service. We are well positioned to benefit
from the emergence of new regional gas markets in proximity to our reserves.area's working
environment.
Our long-term strategy is founded on three guiding principles: Enable,
Manage Risk and Value Harvest. We Enable by using our experience and skills to
identify, access and exploit large known resources of hydrocarbons in
underexploited areas around the world that can be developed at low overall finding costs,
produced at low operating costs and converted into proved reserves, production
and value. While our success is dependent uponWe Manage Risk by controlling or mitigating the many factors both within
and outside of our
3
control, in order to achieve this
strategy, we must:
- continuesuch as continuing to improve our financial flexibilityoperating risks, access to markets
and financing strategies;
- exploitflexibility. We Value Harvest our coreexisting assets in Venezuela and Russia; and
- seek and exploit new oil and natural gas resources in our core areas.by rapid
development to convert underdeveloped hydrocarbons into cash.
We intend to continue to seek and exploit new oil and natural gas
reserves in current areas of interest while working toward 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:
-o Focus Our Efforts in Areas of Low Geologic Risk: We intend to focus our
exploration and development activities only in areas of large known proven
hydrocarbons.
-but undeveloped oil and gas
resources.
o 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. In
pursuing new opportunities, we will seek to enter at an early stage and
find local investment partners in an effort to reduce our risk in any
one venture.
-o 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, as well as maximize the amount of
local financing capacity to develop the hydrocarbons and associated
infrastructure.
o Limit Exploration Activities: We do not engage in exploration except in
conjunction with the expansion of an existing reservoir.
Our ability to successfully execute our strategy is subject to
significant risks including, among other things, operating risks, political
risks and financial risks. Operating risks include our ability to 1) maintain
optimal production, 2) achieve maximum reserve recovery and 3) maintain our cost
structure on an economically favorable basis, particularly in Geoilbent in which
we are a minority owner. Political risks in Venezuela are significant, and while
currently partially abated, could again have a negative influence on our
operations and our financial flexibility. In Russia, the oil and gas business is
evolving, but remains subject to local laws and customs, local market operation
and powerful domestic oil and gas companies. Our company is also solely
dependent upon sales of oil and gas, once the Venezuelan gas project is
completed, to fund our operations and service our debt requirements.
Interruptions in Benton-Vinccler's production and cash flow would erode our
financial flexibility and hinder our ability to execute our operating strategy.
In addition, Venezuela recently imposed foreign currency exchange controls which
could increase our costs of operations.
OPERATIONS
The following table summarizes our proved reserves, drilling and
production activity, and financial operating data by principal geographic area
at and forthe end of each of the three years endedending December 31.31, 2002. All Venezuelan
reserves are attributable to an operating service agreement between
Benton-Vinccler and an
affiliate of PDVSA 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 interestinterests 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, 2002, 2001 2000 and 19992000 reflect results from Geoilbent for the twelve
5
months ended September 30, 2002, 2001 2000 and 1999,2000, and from Arctic Gas, until it
was sold on April 12, 2002, for the twelve months ended September 30, 2001 and
2000.
We own 80 percent of Benton-Vinccler. The reserve information presented
below is 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. Reserves include production
projected through the end of the operating service agreement in July 2012.
4
BENTON-VINCCLER
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YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
2002 2001 2000
1999
-------- -------- ------------------ ---------- ----------
(DOLLARS IN 000'S)000's)
RESERVE INFORMATION:INFORMATION
Proved reserves (MBbls)............................(MBOE) 102,534 83,611 98,431 107,969
Discounted future net cash flow attributable to proved
reserves, before income taxes............ $176,210 $368,464 $521,346taxes $ 481,284 $ 176,210 $ 368,464
Standardized measure of future net cash flows...... $163,328 $284,549 $380,865flows $ 317,799 $ 163,328 $ 284,549
DRILLING AND PRODUCTION ACTIVITY:
Gross wells drilled................................drilled 13 8 26 2
Average daily production (Bbls).................... 26,598 26,788 25,585 26,485
FINANCIAL DATA:
Oil and natural gas revenues....................... $122,386 $139,890revenues $ 89,060126,731 $ 122,386 $ 139,890
Expenses:
Operating expenses and taxes other than on income........................................ 42,212income 31,608 42,175 46,848
38,839
Depletion.......................................... 22,119Depletion 22,685 21,175 15,708 14,732
Income tax expense................................. 8,932 19,768 3,822
-------- -------- --------expense 4,866 9,083 20,307
---------- ---------- ----------
Total expenses............................. 73,263 82,324 57,393
-------- -------- --------expenses 59,159 72,433 82,863
---------- ---------- ----------
Results of operations from oil and natural gas
producing activities............................activities $ 49,12367,572 $ 57,56649,953 $ 31,667
======== ======== ========57,027
========== ========== ==========
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 (at September 30 for each respective year), drilling and
production activity, and financial operating data for the twelve months ended
September 30, 2002, 2001 2000, and 1999.2000.
GEOILBENT
-------------------------------------------------------------------
YEAR ENDED SEPTEMBER 30,
-------------------------------------------------------------------
2002 2001 2000
1999
------- -------- ------------------ ---------- ----------
(DOLLARS IN 000'S)000's)
RESERVE INFORMATION:INFORMATION
Proved reserves (MBbls)............................. 29,669 32,615 36,415 25,356 29,668 32,614
Discounted future net cash flow attributable to proved
reserves, before income taxes............. $81,125 $140,160 $215,348taxes $ 117,230 $ 81,125 $ 140,160
Standardized measure of future net cash flows....... $70,648 $114,725 $169,077flows $ 92,939 $ 70,648 $ 114,725
DRILLING AND PRODUCTION ACTIVITY:
Gross development wells drilled.....................drilled 6 39 39 28
Net development wells drilled.......................drilled 2 13 13 10
Average daily production (Bbls)..................... 6,438 4,830 3,945 3,975
6
GEOILBENT
-----------------------------
YEAR ENDED SEPTEMBER 30,
-----------------------------
2001 2000 1999
------- -------- --------
(DOLLARS IN 000'S)
FINANCIAL DATA:
Oil and natural gas revenues........................ $34,394revenues $ 26,77031,039 $ 12,51134,261 $ 26,716
Expenses:
SellingOperating, selling and distribution expenses................ 3,358 1,568 1,369
Operating expenses
and taxes other than on income......................................... 12,671 9,548 4,274
Depletion...........................................income 16,902 16,083 10,831
Depletion 9,237 5,072 3,249
3,287
Income tax expense.................................. 3,204 3,215 442
------- -------- --------expense 1,955 3,742 3,306
---------- ---------- ----------
Total expenses.............................. 24,305 17,580 9,372
------- -------- --------expenses 28,094 24,897 17,386
---------- ---------- ----------
Results of operations from oil and natural gas
producing activities............................. $10,089activities $ 9,1902,945 $ 3,139
======= ======== ========9,364 $ 9,330
========== ========== ==========
As of December 31, 2001 2000 and 1999,2000, we owned, free of any sale and/orand
transfer restrictions, 39 29 and 2429 percent, respectively, 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 (at September 30 for each respective year),
drilling and production activity, and financial operating data for the period
until it was sold on April 12, 2002, and twelve months ended September 30, 2001
and 2000.
5
ARCTIC GAS COMPANY
-----------------------------------------------------------------
YEAR ENDED SEPTEMBER 30,
-----------------------------------------------------------------
2002 2001 2000
1999
-------- ------- ---------------- ---------- ----------
(DOLLARS IN 000'S)000's)
RESERVE INFORMATION:INFORMATION
Proved reserves (MBOE)................................ (a) 55,631 41,236 3,714
Discounted future net cash flow attributable to proved
reserves, before income taxes...................... $108,400 $74,517 $8,241taxes (a) $ 108,400 $ 74,517
Standardized measure of future net cash flows.........flows (a) $ 82,205 $56,880 $6,836$ 56,880
DRILLING AND PRODUCTION ACTIVITY:
Gross wells reactivated...............................reactivated (a) 2 4 --
Average daily production (BOE)........................ 189 502 134 --
FINANCIAL DATA:
Oil and natural gas revenues..........................revenues $ 3,554 $ 4,016 $ 889
$ --
Expenses:
Selling and distribution expenses..................expenses 1,429 1,165 -- --
Operating expenses and taxes other than on income...........................................income 1,673 2,215 604
--
Depletion.............................................Depletion 139 311 78
--
-------- ------- ---------------- ---------- ----------
Total expenses................................expenses 3,241 3,691 682
--
-------- ------- ---------------- ---------- ----------
Results of operations from oil and natural gas
producing activities...............................activities $ 313 $ 325 $ 207
$ --
======== ======= ================ ========== ==========
(a) Arctic Gas was sold on April 12, 2002
SOUTH MONAGAS UNIT, VENEZUELA (BENTON-VINCCLER)
General
In July 1992, Bentonwe 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,Lagoven, S.A., an affiliate of
PDVSA, to reactivate and further develop the Uracoa, Tucupita and 7
Bombal Fields.fields.
These fields comprise the South Monagas Unit. 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:
-o mergers;
-o consolidations;
-o sales of substantially all of its corporate assets;
-o change of business; and
-o 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 construction
projects, governmental relations 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 South Monagas Unit, including all necessary investments to reactivate and
develop the fields comprising the South Monagas 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.6
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. Since 1992, the maximum total fee received by
Benton-Vinccler has approximated 48 percent of West Texas Intermediate crude oil
("WTI") price.
Benton-Vinccler has constructed a 25-mile oil pipeline from its oil
processing facilities at Uracoa to PDVSA's storage facility, the custody
transfer point. The operating service agreement specifies that the oil stream
may contain no more than one percent base sediment and water. Quality
measurements are conducted both at Benton-Vinccler's facilities and at PDVSA's
storage facility. In December 1999,January 2002, Benton-Vinccler enteredinstalled a continuous flow
measuring unit at its facility to closely monitor the quantities of hydrocarbons
delivered to PDVSA.
At the end of each quarter, Benton-Vinccler prepares an invoice to
PDVSA based on barrels of oil accepted by PDVSA during the quarter, using
quarterly adjusted contract service fees per barrel. Payment is due under the
invoice by 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 an alliance with
SchlumbergerBenton-Vinccler's account in a commercial bank in the United
States. While PDVSA has timely paid its past invoices, payment of the invoice
for the Uracoa field which includes reservoir modeling, drillingfourth quarter 2002 deliveries was seven days late. PDVSA indicated that
the late payment was due to business interruptions resulting from the national
civil work stoppage in Venezuela.
Natural Gas Sales Contract
On September 19, 2002, Benton-Vinccler and downhole electrical pumping. The alliance gives us access to Schlumberger's
technical resources and personnel and provides financial incentives for
Schlumberger based on their performance. The incentives are designed to reduce
drilling costs, improve initial production rates of new wells and increase the
average life of downhole pumps. Schlumberger maintains a full-time staff at
Benton-Vinccler's office as part of this agreement. WePDVSA signed an amendment to
the allianceoperating service agreement, providing for the delivery of up to 198 Bcf of
natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales are
expected to commence at a rate of 40 to 50 MMcf of natural gas per day in 2001 whereby Schlumbergerthe
fourth quarter of 2003 and gradually increase up to 70 MMcfpd in 12 to 18 months
from the initial sale. In addition, Benton-Vinccler agreed to provide drillingsell to PDVSA 4.5
million barrels of oil at $7.00 per barrel beginning with our first gas sale.
Initial gas production will come from Uracoa, which allows us to more
efficiently manage the reservoir and completion services for neweliminate the restrictions on producing oil
wells utilizing fixed lump-sum pricing.with high gas to oil ratios. The amended
alliance continuesgas reserves in Bombal will be used to
provide incentives to Schlumberger designed to improve
initial production rates of new wells and to increasemeet the average lifefuture terms of the downhole pumps.
We drilled eight oil wellsgas contract in 2001. As part of our strategic shift in focus
on the value of the barrels produced, we suspended the development drilling
program for a period2005 or 2006.
An initial capital investment of approximately eight months starting$26 million will be
required to build a 64-mile pipeline with a normal capacity of 70 MMcf of
natural gas per day and a design capacity of 90 MMcf of natural gas per day, a
gas gathering system, upgrades to the UM-2 plant facilities and new gas
treatment and compression facilities. We plan to start fabrication and
construction process for the gas pipeline in January 2001.
During this period, withearly 2003. Benton-Vinccler has
borrowed $15.5 million under a project loan for the assistance of alliance partner Schlumberger, all
aspects of operations were thoroughly reviewed to integrate field performance to
date with revised computer simulation modelinggas pipeline and improved well completion
technology. We believe this helped to produce a streamlinedrelated
facilities and more effective
infill drillingthe remainder will be funded from existing cash balances and
well workover program that is part of an overall reservoir
management strategy.
8
internally generated cash flow.
Location and Geology
The South Monagas 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 South Monagas Unit is approximately 51 miles long and
eight miles wide and consists of 157,843 acres, of which the fields comprise
approximately one-half.one-half of the acreage. At December 31, 2001,2002, proved reserves
attributable to our Venezuelan operations were 104,514 MBbls (83,611 MBbls128,168 MBOE (102,534 MBOE net to
Benton)Harvest). This represented approximately 5080 percent of our proved reserves.reserves at
year end. Benton-Vinccler has been primarily developing the Oficina sands in the
Uracoa Field. The Uracoa Field contains 7062 percent of the South Monagas Unit's
proved reserves. In December
2001, Benton-Vinccler began the development of the Tucupita Field. We intend to
drill seven oil wells and two water injection wells in the Tucupita Field during
2002. Benton-Vinccler is currently reinjecting most of the associated
natural gas produced at Uracoa back into the reservoir.
Natural Gas Sale Negotiations
We are currently in discussions with PDVSA regarding the negotiation of a
contract contemplating the sale of natural gas produced from the South Monagas
Unit. Benton-Vinccler anticipates natural gas from the Uracoa and Bombal Fields
could be dedicated to PDVSA over the remaining life of the operating service
agreement. If the parties reach an agreement, construction of a pipeline,
compressor and other necessary infrastructure may be required in order to
deliver natural gas to PDVSA in accordance with agreed specifications. However,
there are no assurances that a natural gas contract will result from these
negotiations.
Drilling and Development Activity
Benton-Vinccler drilled 811 oil and 2 water injection wells in 2002 and
had an average of 133131 wells on production in all fields in 2001.2002.
7
URACOA FIELD
Benton-Vinccler has been developing the South Monagas Unit since 1992,
beginning with the Uracoa Field.
The following table sets forth the Uracoa Field
drilling activity and production information for each of the quarters presented:
WELLS DRILLED
--------------------- AVERAGE DAILY
VERTICAL HORIZONTAL PRODUCTION FROM FIELD (BBLS)
-------- ---------- ----------------------------
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
2001:
First Quarter........................... -- -- 26,100
Second Quarter.......................... -- -- 20,500
Third Quarter........................... 2 -- 19,700
Fourth Quarter.......................... 5 1 20,700
In 1998, we developed a geologic and reservoir simulation study which
indicated the viability of multiple additional primary infill wells in the
Uracoa Field. We believe many of these new locations are in underdeveloped sands
where the model may help to optimize well spacing and location. In the more
developed
9
areas of the field, we used the model to verify our economic assumptions
regarding 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
which we believe will assist in optimizing field management. The computer
simulation study, built jointly with Schlumberger, may update and extend the
1998 study performed 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. We anticipate completing a
revised Uracoa Field development plan, incorporating the results of this study,
in mid-2002.
Since 1992, we have reactivated 15 previously drilled wells and drilled 147
new wells in the Uracoa Field using improved drilling and completion techniques
that had not previously been utilized on the field. Of the new wells drilled, 6
wells were drilled as water or natural gas injector wells and an additional 6
producing wells have been converted into injection wells. Two of the drilled
injector wells were subsequently converted into producing wells.
We processBenton-Vinccler processes the oil, water and natural gas produced from
the Uracoa Field in the Uracoa central processing unit. We shipBenton-Vinccler ships
the processed oil via pipeline to the PDVSA custody transfer point.
We treatBenton-Vinccler treats and filterfilters produced water, and then re-injectre-injects it into
the aquifer to assist the natural water drive. We re-injectBenton-Vinccler re-injects
natural gas into the natural gas cap primarily for storage conservation. The
major components of the 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 Mcf40 to 45 MMcf of natural gas per day.
In August 1999, Benton-Vinccler sold its 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.
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 1.9 MMBbls of oil at an average rate of 987 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 and
reactivated an additional nine wells. All five drilled wells encountered high
oil saturations, with an average initial production rate of 922 Bbls of oil per
day. In 2001, weBenton-Vinccler reactivated nine wells in Tucupita and identified seven new
well locations in what we believe are undepleted portions of the Tucupita Field,
which we anticipate drilling in 2002. As2002
completed eleven oil producers and two water injectors. The oil is transported
through a result of our analysis of the
potential in the Tucupita Field, and for environmental and safety reasons, we
constructed a $10.3 million, 31-mile, 20,000 Bbl20 MBbl per day capacity oil pipeline constructed in 2001
from Tucupita to the Uracoa central processing unit in 2001.
We areunit.
Benton-Vinccler is reinjecting produced water from Tucupita into the
aquifer to aid the natural water drive and we utilize a portion of the
associated natural gas to operate a power generation facility.facility to supply our
power needs.
To date, we have drilled one well in the Bombal Field and reactivated
another.
The Bombal Field is now shut-in. We are currently evaluating the future
development plan for Bombal in light of our negotiations with PDVSA concerning
the sale of natural gas.
10
Customers and Market Information
OilUnder the operating service agreement, oil produced in Venezuela is delivered to
PDVSA under the terms of an
operating service agreement for an operating service fee. Benton-Vinccler has
constructedFrom December 14, 2002 through February 6, 2003, no
sales were made because of PDVSA's inability to accept our oil due to the
national civil work stoppage in Venezuela. As a 25-mile oil pipeline from its oil processing facilities at Uracoa
to PDVSA's storage facility. This isresult, 2002 sales were reduced
by approximately 550,000 barrels. In restoring production, we encountered
problems with some of our wells, but we do not believe the custody transfer point. The service
agreement specifies that the oil stream may contain no more than one percent
base sediment and water. Quality measurements are conducted both at
Benton-Vinccler's facilities and at PDVSA's storage facility. We installed a
continuous flow measuring unit at our facility to closely monitor the quantities
of hydrocarbons delivered to PDVSA. This flow measuring unit was completed in
January 2002. PDVSA provides Benton-Vinccler with a daily acknowledgment
regarding the amount of oil accepted during the previous day. Atassociated costs will
be material. By the end of each
quarter, Benton-Vinccler prepares an invoice to PDVSA for that quarter's
deliveries. PDVSA pays the invoice by the endMarch 2003, our average production was approximately
24,000 barrels of the second month after the endoil per day. While we have substantial cash reserves, a
prolonged loss of the quarter. Invoice amounts and payments are denominated in U.S. dollars.
Payments are wire transferred into Benton-Vinccler's account insales could have a commercial
bank in the United States.
Natural gas produced by Benton-Vinccler is currently re-injected or used as
fuel gas in operations. We are currently in negotiations with PDVSA for sale of
natural gas in the South Monagas Unit. There are no assurances that natural gas
contracts will result from these negotiations.material adverse effect on our financial
condition.
Employees and Community Relations
Benton-Vinccler has a highly skilled staff of predominately Venezuelan
nationals. Benton-Vinccler172 local employees and 5
expatriates and has also formed successful and supportive relationships with
local government agencies and communities.
There are 174
local employees and 5 expatriates working at Benton-Vinccler.
Benton-Vinccler has invested in a Social Community Program that
includes medical care programs such as in ophthalmologic and dental care. From 1994 to
2001, a total of 340 eye surgeries were performed on patients ranging in age
from two to eighty-five years, solelycare, as a result of financial assistance
provided by Benton-Vinccler. The dental program focuses on comprehensive dental
care for public school children. From 1994 to 2001, the program has involved
approximately 1,825 children. Additionalwell as
additional social investments include sponsoringincluding the purchase of medicines and medical
equipment in local communities within the South Monagas Unit, as well as supporting local schools, education programs and
environmental improvements.Unit.
Health, Safety and Environment
Benton-Vinccler's health, safety and environmental policy is an
integral part of its business. Annually, improvements have been made in operating
performance,Benton-Vinccler continually improves
its policy and practices related to personnel safety, property protection and
environmental management. These improvements can be directly attributed to the
efforts in accident prevention programs and the training and implementation of a
comprehensive Process Safety Management System.
8
NORTH GUBKINSKOYE AND SOUTH TARASOVSKOYE, 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;
- Open Joint Stock Company Minley ("Minley") owns 66 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. Purneftegazgeologia and Purneftegaz (co-founding shareholders)
contributed their interest to Open Joint Stock Company Minley ("Minley") in
2001. Geoilbent's current ownership is as follows:
o Harvest -- 34 percent.
o Minley -- 66 percent.
We believe that we have developed a good relationship with our shareholderMinley and
have not experienced any disagreements on major operational matters. Purneftegazgeologia and Purneftegas (co-founding
shareholders) contributed their interest to Minley in 2001. We are
reviewing ways to improve the operations, but we areas a minority partner and thereforeshareholder we may
not be able to fully effect changes in operations, if indicated as necessary or
desirable by our review. Geoilbent shareholder action requires a 67 percent
majority vote of its shareholders.
11
Geoilbent's oil and gas fields are situated on land belonging to the
Russian Federation. Geoilbent obtained licenses from the local authorities and
pays unified production taxes to explore and produce oil and gas from these
fields. Licenses will expire in September 2018 for the North Gubkinskoye field,
and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4
of the Russian Federal Law 20-FZ, dated January 2, 2000, the license may be
extended over the economic life of the lease at Geoilbent's option. Geoilbent
intends to extend such licenses for properties that are expected to produce
subsequent to their expiry dates. Estimates of proved reserves extending past
the license expiration currently represent approximately 5 percent of total
proved reserves.
Location and Geology
Geoilbent develops, produces and markets crude oil from the North
Gubkinskoye and South Tarasovskoye Fields in the West Siberia region of Russia,
located approximately 2,000 miles northeast of Moscow. Large provenproved oil and gas
fields surround all four of Geoilbent's licenses.
The North GubinskoyeGubkinskoye Field is included inside 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. The field is a large anticlinal structure with multiple pay
sands. The development to date has focused on the Cretaceous BP 8, 9, 10, 11 and
12 reservoirs with minor development in the BP 6, 7 and 7Jurassic reservoirs.
Geoilbent is currently flaring the produced natural gas in accordance with
environmental regulations, although it is exploring alternatives to construct a
natural gas processing plant and to market the natural gas.gas and natural gas
liquids.
The South Tarasovskoye Field is located a few miles southeast of North GubinskoyeGubkinskoye
Field and straddles the eastern boundary of the Urabor Yakhinsky exploration
block acquired by Geoilbent in 1998. It is estimated that a majority of the
field is situated within the block. The remaining portion of the field falls
within a license block owned by Purneftegaz. Production began in early 2001 from
a discovery well drilled close to the boundary by Purneftegaz. Only 521 of
Geoilbent's 763,558 acres in this field are reflected as proved-developed acres.
The development to date has focused on the Cretaceous BP 7, 8, 9 and 10, and the
Jurassic reservoirs. All of the current production in South Tarasov is achieved
from the main anticlinal feature.
Geoilbent also holds rights to two more license blocks comprising
426,199 acres in the West Siberia region of Russia.
Drilling, Development, Customer and Development ActivityMarket Information
Currently there are 109 wells in production in North Gubkinskoye and 18
in production in South Tarasovskoye. In addition, there are 37 and 2 injectors,
respectively, currently injecting water in each field.
Until Geoilbent commenced initialbegan operations in the North Gubinskoye Field during
the third quarter of 1992, with the construction of a 37-mile oil pipeline and
installation of temporary production facilities. During 2001, approximately 110
wells were producing with 29 injection wells. Drilling in South Tarasovskoye
Field began at the end of May 2001. The first well was completed on July 23,
2001 for an initial production rate of 1,695 Bbls oil per day. In 2001,
Geoilbent drilled 11 wells at an average production rate of 880 Bbls oil per
day. By the end of 2001, total production from the 11 wells was 9,700 Bbls oil
per day. Plans are to drill between 50 to 60 more wells by 2005 to more fully
develop the portion of the field within the Urabor block.
The following table sets forth drilling activity and production information
for each of the quarters presented:
AVERAGE DAILY
WELLS DRILLED PRODUCTION FROM FIELD (BBLS)
------------- ----------------------------
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
2001:
First Quarter.................................. 7 13,900
Second Quarter................................. 8 13,300
Third Quarter.................................. 12 14,700
Fourth Quarter................................. 12 14,900
12
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 developmentwas one of the North Gubkinskoye Field from the European
Bank for Reconstructionlargest non-producing oil and Development ("EBRD") and the International Moscow
Bank. A total of $48.5 million had been advanced from the loan facility. Debt
outstanding under the facility at December 31, 2001 was $38.6 million. As of
September 30, 2001, Geoilbent was not in compliance with the current ratio
covenant but received a waiver from EBRD through March 31, 2002.
Geoilbent has reduced its 2002 capital budget to approximately $16.6
million, of which $2.7 million is for the North Gubkinskoye Field, $9.7 million
is for the South Tarakovskoye Field, $2.2 million is to carry out seismic and
related exploration activity and $2.0 million is for natural gas plant economic,
technical and feasibility studies. Geoilbent's 2002 operating budget includes
$16 million for principal payments on the loan facility. In addition, Geoilbent
had outstanding accounts payable of $26.6 million as of December 31, 2001,
primarily to contractors and vendors for drilling and construction services.
Although Geoilbent's reduced capital expenditure budget may help to
alleviate any shortfall of funds available to make payments to the banks and its
creditors as those payments come due, it is uncertain that Geoilbent's cash flow
from operations will be sufficient to do so, and it may be necessary for
Geoilbent to obtain capital contributions from its partners, including the
Company, to have sufficient funds to make these payments on a timely basis.
Although the Company may consider making such a capital contribution, there can
be no assurances that the Company will do so, nor can there be any assurances
that Geoilbent's other partner will be willing or able to do so. Under Russian
law, a creditor can force a company into involuntary bankruptcy if the company's
payments have been due for more than 90 days.
Customers and Market Information
Geoilbent's 37-mile pipeline runs from the field to the main pipelinefields in the area whereregion. Geoilbent
transfers thetransports its oil production to Transneft, the state oil pipeline
9
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 Rosneftegasexport handlehandles all export oil sales. All export
sales, have beenwhich are paid
in U.S.US dollars into Geoilbent's accountbank account. In 2002, approximately 34% of
Geoilbent's production was sold in Moscow.
Domestic sales are paid in Russian Rubles. During 2001, Geoilbent sold
approximately 49 percent of its production in the world export market and 51 percent66% in the
domestic Russian market. Excise, pipelineGeoilbent's domestic Russian crude oil price declines
significantly in the winter months. For example, during the period from
September 30, 2002 until December 31, 2002. In this same period, Russian export
prices increased from approximately $20 to $29 per barrel, however, Geoilbent's
average price declined $5.05 in value between these two periods. Geoilbent could
not export more crude oil due to Transneft and other tariffsthe winter export limitations.
Geoilbent is continuing to pursue its oil development program. The
current production facilities are operating at or near capacity and taxes continuewill need to
be leviedexpanded to accommodate future production increases. Currently gas production
from North Gubkinskoye is consumed as fuel with the remainder being flared.
In 1996, Geoilbent secured a loan from the European Bank for
Reconstruction and Development ("EBRD") to develop a portion of the oil and
condensate reserves of the North Gubkinskoye Field. The outstanding debt balance
of $22 million on allthe debt to EBRD has been restructured into a new $50 million
loan facility, which will be used to reduce payables and implement the South
Tarasovskoye oil producersdevelopment in 2003. On March 12, 2003 Geoilbent drew $8.0
million under the loan to reduce payables. However, there can be no assurance
that this draw on the credit facility will be adequate to permit Geoilbent to
meet the current financial ratio requirement under the credit facility. If
Geoilbent fails to meet the ratio requirements for two consecutive quarters it
will result in an event of default whereby EBRD may, at its option, demand
payment of the outstanding principal and certain exporters, including an oil export
tariffinterest. In addition, the restructured
loan agreement requires that decreased in 2002 to $8.00 per ton (approximately $1.10 per barrel)
from 23.4 Euros per ton (approximately $2.85 per barrel). We areGeoilbent implement a new management information
system by May 1, 2003. Geoilbent will be unable to predicttimely satisfy this
requirement which also results in an event of default whereby EBRD may, at its
option, demand payment of the impactoutstanding principal and interest. For a more
complete description of taxes, dutiesthe terms and other burdens forconditions of the future for ourEBRD loan and
Geoilbent's covenant obligations, See Item 7 - Risk Factors and Note 9 - Russian
operations.
Employees;Operations.
Employees, Community and Country Relations
Geoilbent employs Russian nationals almost exclusively. Presently, there
are two full-timesix expatriates working with Geoilbent and 700 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 resideresides in the area
of oilfield operations.
13
EAST URENGOY, RUSSIA (ARCTIC GAS COMPANY)
General
See The Proposed Sale of Arctic Gas Company if Closed, Will Reduce the
Impact of Leverage in Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations, and Note 16 to the Audited
Financial Statements in Item 14 -- Exhibits, Financial Statement Schedules and
Reports on Form 8-K.
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 a significant
portion of the world's natural gas reserves. Both license blocks are on the
eastern flank of the giant Urengoy natural gas field, which currently produces
hydrocarbons from Cenomanian reservoirs. Under the terms of agreements signedsold 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, 2001, we had provided $28.5 million of credit, of which
$28.1 million had been applied to the release of restrictions on the shares. As
a result, we removed restrictions from shares representing an approximate 11
percent equity interest. From 1998 through December 2001, we separately
purchased shares representing an additional 28 percent equity interest not
subject to any sale or transfer restrictions. Including the additional purchased
shares, as of December 31, 2001, we owned a total of 68 percent of the voting
shares of Arctic Gas, of which 39 percent was not subject to restrictions.
The following table summarizes our ownership interests of Arctic Gas
Company:
AS OF
DECEMBER 31,
------------
2001 2000
---- ----
Shares released from restrictions........................... 11% 9%
Additional purchased shares................................. 28% 20%
-- --
Total shares not subject to restrictions.................... 39% 29%
Shares subject to restrictions.............................. 29% 31%
-- --
Total ownership............................................. 68% 60%
== ==
In February 2002, we announced the Proposed Arctic Gas Sale. On March 22,
2002, we were notified that the Transaction had received the requisite consents
from the Russian Ministry for Antimonopoly Policy and Support for
Entrepreneurship. On March 28, 2002, we received the first payment ($120.0
million) of the Proposed Arctic Gas Sale proceeds.
Location and Geology
The Samburg and Yevo-Yakha License Blocks comprise 794,972 acres and are
situated approximately 150 miles north of our Geoilbent affiliates' operations
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.
Drilling and Development Activity
Arctic Gas has reactivated 8 previously drilled oil wells through March 23,
2002. We are trucking oil to storage facilities where it is collected for sale.
Arctic Gas is currently producing approximately 2,700 Bbls of oil per day.
14
The following table sets forth reactivation activity and production
information for each of the quarters presented:
WELLS AVERAGE DAILY
REACTIVATED PRODUCTION FROM FIELD (BBLS)
----------- ----------------------------
2000:
First Quarter................................... -- 400
Second Quarter.................................. 2 940
Third Quarter................................... 1 1,500
Fourth Quarter.................................. 1 1,700
2001:
First Quarter................................... 1 1,300
Second Quarter.................................. -- 1,000
Third Quarter................................... -- 2,300
Fourth Quarter.................................. 1 2,100
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 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. See Note 16
to the Audited Financial Statements in Item 14 -- Exhibits, Financial Statement
Schedules and Reports on Form 8-K. Arctic Gas had entered into contracts with
various parties concerning the export of natural gas. All natural gas contracts
have been cancelled pursuant to the Proposed Arctic Gas Sale.
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.
Employees; Community and Country Relations
Arctic Gas is a9 - Russian
company that employs Russian nationals almost
exclusively. Presently, there are 2 full-time expatriates working with Arctic
Gas and 161 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.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 1.01.25 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.another company. The
territorial dispute has lasted for many years, and there has been limited
exploration and no development activity in the area under dispute. 15
We cannot predict how or when, if at all, this dispute will be resolved or
whether it would resultAs part of
our review of Company assets, we conducted a third-party evaluation of the
WAB-21 area. Through that evaluation and our own assessment, we recorded a $13.4
million impairment charge in our interest being reduced.the second quarter of 2002.
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.
10
Drilling and Development Activity
Due to the sovereignty issues between China and Vietnam, we have been
unable to pursue an exploration program during phase one of the contract. As a
result, we have obtained extensions,a license extension, with the current extension in
effect until May 31, 2003.2005.
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. We acquiredhad a 10035 percent working interest in the Lakeside Exploration
Prospect, in Cameron Parish, Louisiana. We farmed out 90 percent ofIn September 2002, we determined the workingClaude
Boudreaux #1 exploratory well was not prospective for hydrocarbons and assigned
our entire interest in the prospect for
$0.5 million cash and a 16.2 percent carried interest in the first well. We
anticipate that drilling of the well may commence in 2002. The agreement with
Coastline was terminated on August 31, 2001. However, certain ongoing operations
related to the Lakeside Exploration Prospect are conducted by Coastline onto a consulting basis.
In March 1997, wethird party and
recognized a $1.1 million impairment.
We acquired a 40100 percent participation interest in three California State offshore
oil and natural gas leases ("California Leases") and a parcel of onshore property 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 theLLC. All capitalized costs associated with the California
Leases of $9.2 millionhave been fully impaired. The California Leases have expired and the
joint interest receivable of $3.1
million due from Molino Energy at December 31, 1999. However, we continue to
evaluateCompany has issued the prospect for potential future drilling activities.
16
required quitclaim deed, is plugging and abandoning the
previously drilled exploratory wells and will undertake any required lease and
land reclamation. It is believed that these costs will not be material.
ACTIVITIES BY AREA
The following table summarizes our consolidated activities by area.
Total Assets represents all assets including long-lived assets accounted for
under the equity method:
OTHER TOTAL
(IN THOUSANDS) VENEZUELA FOREIGN FOREIGN UNITED STATES TOTAL ASSETS
- -------------- --------- -------- -------- ------------- --------
(IN THOUSANDS)------------
YEAR ENDED DECEMBER 31, 2002
Oil sales $126,731 $126,731 $126,731
Total Assets $209,733 $ 52,302 $262,035 $73,157 $335,192
YEAR ENDED DECEMBER 31, 2001
Oil sales.....................sales $122,386 $122,386 $122,386
Total Assets..................Assets $167,671 $100,801 $268,472 $79,679 $348,151
YEAR ENDED DECEMBER 31, 2000
Oil and natural gas sales.....sales $139,890 $139,890 $ 394 $140,284
Total Assets..................Assets $166,462 $ 78,406 $244,868 $41,579 $286,447
YEAR ENDED DECEMBER 31, 1999
Oil sales..................... $ 89,060 $ 89,060 $ 89,060
Total Assets.................. $124,942 $ 61,989 $186,931 $89,380 $276,311
RESERVES
Estimates of our proved reserves as of December 31, 20012002 and 20002001 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.L.P., independent petroleum engineers. The
following table sets forth information regarding estimates of proved reserves at
December 31, 2001.2002. 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. Russia's reserves reflect our 34 percent equity
interest in Geoilbent. 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, 20012002 because of a lack of sales and/orand
transportation contracts in place.
Geoilbent
and Benton-Vinccler are currently evaluating alternatives to market this natural
gas. Natural gas proved reserves have been recognized for Arctic Gas, which has
transportation and marketing contracts in place. The marketing contracts were
cancelled in anticipation of the Proposed Arctic Gas Sale. See Note 16 to the
Audited Financial Statements in Item 14 -- Exhibits, Financial Statement
Schedules and Reports on Form 8-K. The cancellation will have an impact on the
Equity Affiliate-Russia reserves found on Table IV -- Quantities of Oil and
Natural Gas Reserves.11
NET CRUDE OIL AND CONDENSATE (MBBLS)
--------------------------------------(MBbls)
--------------------------------------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
---------- ------------ ------------------------- ------------------- ----------------
Venezuela........................................... 41,172 42,439 83,611
Geoilbent........................................... 15,658 14,011 29,669
Arctic Gas(1)....................................... 2,484 18,479 20,963
------ ------ -------
Total............................................. 59,314 74,929 134,243
====== ====== =======
Venezuela........................................ 43,066 33,069 76,135
Russia........................................... 11,840 12,941 24,781
----------------- ------------------- ----------------
Total.................................... 54,906 46,010 100,916
================= =================== ================
NET NATURAL GAS (MMCF)
-----------------------------------(MMcf)
--------------------------------------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
Arctic Gas(1)....................................... 21,292 186,718 208,010
====== ======= =======----------------- ------------------- ----------------
Venezuela........................................ 84,000 74,400 158,400
================= =================== ================
- ---------------
(1) Based on 39 percent ownership not subject to restrictions as of December 31,
2001.
17
Estimates of commercially recoverable oil and natural gas reserves and
of the future net cash flows derived therefromthere from are based upon a number of
variable factors and assumptions, such as:
-o historical production from the subject properties;
-o comparison with other producing properties;
-o the assumed effects of regulation by governmental agencies; and
-o 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,there from, 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 6346 percent of our total proved reserves were undeveloped as of
December 31, 2001.
Therefore, the2002.
The following costs therefore will likely vary from our estimates and
such variances may be material:
- actual production;
- oil sales;
-o severance and excise taxes;
-o export tariffs;
-o development expenditures;
-o workover and remedial expenditures;
-o abandonment expenditures; and
-o 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:
-o actual production;
-o oil sales;
o supply and demand for oil and natural gas;
-o availability and capacity of gathering systems and pipelines;
-o changes in governmental regulations or taxation; and
-o the impact of inflation on costs.
The timing of actual future net oil sales and natural gas sales from proved
reserves as well as the year-end price, 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.industry
and the political risks associated with operations in Venezuela and Russia.
Discounted present value, no matterregardless of 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
12
be inaccurate. For the period ending 18
December 31, 2001,2002, we reported $365.7$526.7
million of discounted future net cash flows before income taxes from proved
reserves based on the SEC's required calculations.
PRODUCTION, PRICES AND LIFTING COST SUMMARY
In the following table we have set forth by country our net production,
average sales prices and average lifting costsoperating expenses for the years ended December
31, 2002, 2001 2000 and 1999.2000. The presentation for Venezuela includes 100 percent of
the production, without deduction for minority interest. Geoilbent (34 percent
ownership) and Arctic Gas (39 percent,and 29 percent and 24 percent ownership not subject to any sale
or transfer restrictions at December 2001 2000 and 1999,2000, respectively), which are
accounted for under the equity method, have been included at their respective
ownership interest in the consolidated financial statements based on a fiscal
period ending September 30 and, accordingly, our results of operations for the
years ended December 31, 2002, 2001 2000 and 19992000 reflect results from Geoilbent for
the twelve months ended September 30, 2002, 2001 2000 and 1999,2000, and from Arctic Gas
until it was sold on April 12, 2002, and for the twelve months ended September
30, 2001 and 2000.
YEARSYEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------
2002 2001 2000
1999
--------- --------- -------------------- ----------- -----------
VENEZUELA
Net Crude Oil Production (Bbls)................... 9,708,295 9,777,516 9,364,088 9,666,958
Average Crude Oil Sales Price ($ per Bbl)......... $12.52 $14.94 $9.21 $ 13.08 $ 12.52 $ 14.94
Average Lifting CostsOperating Expenses ($ per Bbl)................. $ 3.26 $ 4.30 $ 5.01
$4.02
GEOILBENT
AverageGEOILBENT(a)
Net Crude Oil Production (Bbls)............... 2,349,916 1,762,814 1,444,181 1,451,000
Average Crude Oil Sales Priceprice ($ per Bbl)......... $19.51 $18.54 $8.62 $ 13.21 $ 19.51 $ 18.54
Average Lifting CostsOperating Expenses ($ per Bbl)................. $ 2.09 $ 2.17 $ 2.31
$1.02
ARCTIC GAS (a)(b)
Net Crude Oil Production (Bbls)................... (b) 183,087 48,833 --
Average Crude Oil Sales Priceprice ($ per Bbl)......... $21.93 $18.20 -- (b) $ 21.93 $ 18.20
Average Lifting CostsOperating Expenses ($ per Bbl)................. (b) $ 7.42 $ 7.42 $ 5.97 --
(a) Information represents our ownership interest.
(b) Arctic Gas was sold on April 12, 2002.
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:
-o change in governments;
-o civil unrest;
o price and currency controls;
-o limitations on oil and natural gas production;
-o world demand for crude oil;
-o tax and other laws relating to the petroleum industry;
-o changes in such laws; and
-o 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 isare periodically changed for a
variety of political, economic, environmental and other reasons. Numerous
governmental departments and agencies
19
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.
13
Venezuela
On February 5, 2003, Venezuela imposed currency controls and created
the Commission for Administration of Foreign Currency ("CADIVI") with the task
of establishing the detailed rules and regulations and generally administering
the exchange control regime. These controls fix the exchange rate between the
Bolivar and the U.S. dollar, and restrict the ability to exchange Bolivars for
dollars and vice versa. Oil companies such as Benton-Vinccler are allowed to
receive payments for oil sales in U.S. currency and pay dollar-denominated debt,
dividends and expenses from those payments. We are unable to predict the impact
of the currency controls on us or Benton-Vinccler because the CADIVI has not
issued final regulations. The near-term effect has been to restrict
Benton-Vinccler's ability to make payments to employees and vendors in Bolivars,
causing it to borrow money on a short-term basis to meet these obligations. As
of March 14, 2003, these short-term borrowings have been repaid and while we now
have Bolivars to meet our current obligations, the situation could change. In
addition, the currency controls have increased the cost of Benton-Vinccler's
Bolivar denominated debt. We plan to prepay the Bolivar denominated debt as of
March 31, 2003.
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. Capitalapproval including capital expenditures to
comply with Venezuelan environmental regulations. No capital expenditures to
comply with environmental regulations relating to the reinjection of natural gaswere required in the field and water disposal were $0.1 million in 2001 and $1.1 million in
2000.2002. 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 submitsubmits annual production and development plans, which
include information necessary for permits and approvals for theirits 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 submitGeoilbent submits annual production targets and quarterly export nominations for
oil pipeline transportation capacity to the Ministry of Fuel and Energy.
Geoilbent and Arctic Gas areis 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.
Effective in August 2001, a new tariff structure on exported oil was
instituted. The 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 angovernment sets the maximum crude oil export tariff that decreasedrate
as a percentage of the customs dollar value of Urals, Russia's main crude export
blend. Under the current system when the Urals price is in a range of $109.50 to
$182.50 per ton ($15 to $25 per Bbl) a tariff of 35 percent is imposed on the
sum exceeding the level of $109.50. When Urals crude is below $109.50 per ton no
tariff is collected. When the price rises above $182.50 per ton, exporters pay a
combined tariff comprising $25.53 per ton, plus a tariff of 40 percent on the
sum exceeding $182.50. By way of example, a $27.00 Ural price per barrel would
incur an export tariff of $4.28 per barrel. Effective January 1, 2002, mineral
restoration tax, royalty tax and excise tax on crude oil production were
abolished and replaced by the unified natural resources production tax. Through
December 31, 2004, the base rate for the unified natural resources production
tax is set at Russian Rubles 340 per metric ton of crude oil produced and is to
be adjusted on the market price of Urals blend and the Russian Ruble/US Dollar
exchange rate. The tax rate is zero if the Urals blend price falls to or below
$8.00 per ton (approximately $1.10 per barrel) from 23.4 Euros per ton (approximately
$2.85 per barrel).barrel. From January 1, 2005, the unified natural resources production
tax rate is set by law at 16.5 percent of crude oil revenues recognized by
Geoilbent based on Regulations on Accounting and Reporting of the Russian
Federation. We are unable to predict the impact of future taxes, duties and
other burdens in the future for our Russianon Geoilbent's operations.
14
DRILLING ACQUISITION AND FINDING COSTS
From commencement of operations through December 31, 2001, we added, net of
production and property sales, approximately 189.8 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 $2.34 per BOE. Our estimate
of future development costs for our undeveloped proved reserves at December 31,
2001 was $1.96 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.UNDEVELOPED ACREAGE
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):
-o $51 million during 2002;
o $44 million during 2001; -and
o $50 million during 2000;
and
- $33 million during 1999.
20
We have drilled or participated through our equity affiliate in the
drilling of wells as follows:
YEARSYEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------------
2002 2001 2000
1999
------------- ------------- ------------------------------ ----------------- -----------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- ----------- ------ ------ ------ ------ ------
WELLS DRILLED:
Exploratory:
Crude oil............................Exploration:
Dry hole......................... 1 0.4 -- -- -- --
-- --
Natural gas.......................... -- -- -- -- -- --
Dry holes............................ -- -- -- -- 3 1.60
Development:
Crude oil............................oil........................ 17 10.8 20 10.5 65 34.1
------ ------ ------ ------ ------ ----
Total ............................ 18 11.2 8 6.410.5 65 34.06 28 9.18
Natural gas.......................... -- -- -- -- -- --
Dry holes............................ -- -- -- -- -- --
--- ----- --- ----- --- -----
TOTAL.............................. 8 6.4 65 34.06 31 10.78
=== ===== === ===== === =====34.1
====== ====== ====== ====== ====== ======
AVERAGE DEPTH OF WELLS (FEET)............. 7,341 6,043 7,048 9,092
PRODUCING WELLS (1):
Crude Oil............................Oil........................ 258 158.2 274 169.9 268 163.6 181 108.0
- ---------------
(1) The information related to producing wells reflects wells we drilled,
wells we participated in drilling and producing wells we acquired.
At December 31, 2001, weIn 2002, Geoilbent participated in the drilling of 39 wells in
Russia.six crude oil
wells.
All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We do not directly own or operate any drilling
equipment.
Geoilbent does own components of the rigs it employs.
AcreageACREAGE
The following table summarizes the developed and undeveloped acreage
that we owned, leased or hadheld under operating service agreement or concession as
of December 31, 2001:2002:
DEVELOPED UNDEVELOPED
--------------- ------------------------------------------------ --------------------------
GROSS NET GROSS NET
------ ------ --------- -------------------- ----------- ----------- -----------
Venezuela..................................... 9,748 7,798 148,095 118,476
Russia(1)..................................... 42,457 14,339 2,109,358 704,002
China.........................................Venezuela (Benton-Vinccler)................. 10,966 8,773 146,877 117,502
Russia (Geoilbent).......................... 36,697 12,477 1,320,146 448,850
China....................................... -- -- 7,470,080 7,470,080
United States................................. -- -- 13,604 12,466
------ ------ --------- ---------
Total............................... 52,205 22,137 9,741,137 8,305,024
====== ====== ========= =========----------- ----------- ----------- -----------
Total....................................... 47,663 21,250 8,937,103 8,036,432
=========== =========== =========== ===========
- ---------------
(1) Russia includes 794,972 gross acres related to Arctic Gas, which is included
based on a 39 percent ownership interest.
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 thepolitical, 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, data resources and facilities substantially greater
than ours.
2115
ENVIRONMENTAL REGULATION
We are subjectVarious federal, state, local and international laws and regulations
relating to environmental regulations administered by foreign
governments, their agencies,the discharge of materials into the environment, the disposal of oil
and natural gas wastes, or other international organizations.otherwise relating to the protection of the
environment, may affect our operations and costs. We are committed to the
protection of the environment and believe we are in substantial compliance with
the applicable laws and regulations. However, regulatory requirements may, and
often do, change and become more stringent, and there can be no assurance that
future regulations will not have a material adverse effect on our financial
position.
EMPLOYEES
At December 31, 2001,2002, we had 19 full-time employees, augmented from
time-to-time with independent consultants, as required. Benton-Vinccler had 174
employees,172
and Geoilbent had 700 employees and Arctic Gas had 161local 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
has obtained license agreements and Arctic Gas have obtained certainother 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.a third party. 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 farm out 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.resolution.
16
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. "Capital Expenditures" means costs associated with
exploratory and development drilling (including exploratory dry holes);
leasehold acquisitions; seismic data acquisitions; geological, 22
geophysical and
land-related overhead expenditures; delay rentals; producing property
acquisitions; and other miscellaneous capital expenditures.
Completion Costs.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.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.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. "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. "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.GAS CAP. "Gas Cap" is the natural gas trapped above the oil in a reservoir.
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.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.OPERATING EXPENSES. "Operating Expenses" 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 and severance taxes.
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.
Proved Developed Reserves.17
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. "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. "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. "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.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
23
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.
Undeveloped Acreage.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 containacreage contains proved
reserves.
ITEM 2. PROPERTIES
In July 2001, we leased for three years office space in Houston, Texas for three years for
approximately $11,000 per month. We lease 17,500 square feet of space in a
California 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.
ITEM 3. LEGAL PROCEEDINGS
On February 17, 1998,See Note 13 - Related Party Transactions regarding the WRT Creditors Liquidation Trust ("WRT Trust")
filed suitA. E. Benton proceeding.
The Company is a defendant in the United States Bankruptcy Court, Western District of Louisiana
against us and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil &
Gas of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLAor otherwise involved in litigation incidental to
Tesla Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties, and that it paid a
price in excess of the fair value of the property. A trial commenced on May 1,
2000 that concluded at the end of August 2000, and post trial briefs were filed.
In August 2001, a favorable decision was rendered in BOGLA's favor denying any
and all relief to the WRT Trust. The WRT Trust has filed a Notice of Appeal with
the Bankruptcy Court; however, we believe that the appeal will result in an
outcome consistent with the court's prior decision.
From 1996 through 1998, we made unsecured loans to our then Chief Executive
Officer, A.E. Benton, bearing interest at the rate of 6 percent per annum. We
subsequently obtained a security interest in Mr. Benton's shares of stock and
stock options. 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. 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. During 2001, we paid Mr. Benton $116,833, and have paid a total
of $536,545 from February 2000 through May 11, 2001 for services performed under
the consulting agreement. On May 11, 2001, Mr. Benton and the Company entered
into a settlement and release agreement under which the consulting agreement was
terminated and Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the repayment of our loans to him. We
currently continue to retain our security interest in Mr. Benton's 600,000
shares of our stock and in his stock options, and we have the right to vote the
shares owned by him and to direct the exercise of his options. Repayment of our
loans to Mr. Benton may be achieved through Mr. Benton's liquidation of certain
real and personal property assets and a phased liquidation of stock resulting in
Mr. Benton's exercise of his stock options. 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. The amount of Mr. Benton's
indebtedness to us is currently approximately $6.5 million. The consulting
agreement provides that if we close the Proposed Arctic Gas Sale, Mr. Benton
will be entitled to receive two percent of our net after-tax cash receipts,
actually received by us in the U.S., resulting from the Proposed Arctic Gas
Sale, excluding any repayment of indebtedness or advances by us to Arctic Gas.
The consulting agreement further provides that under his proposed bankruptcy
plan of reorganization, Mr. Benton will pay five percent of such amounts to us.
Based upon information provided by Mr. Benton's bankruptcy counsel, we
anticipate that under the bankruptcy plan of reorganization that Mr. Benton will
propose, we will receive $1.7 million. This amount does not include the amounts
that we will realize from the exercise of Mr. Benton's options and the
subsequent sale of the resulting shares, nor does it include the net proceeds
that we will receive from the sale of Mr. Benton's 600,000 shares of our stock.
24
In the normal course of our business, there are various other legal
proceedings outstanding.business. In the opinion of management, these proceedings will
not have athere is no litigation which is
material adverse effect on our financial position, results of
operations or liquidity.to the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the three month period ended December 31, 2001, no matter was
submitted to a vote of security holders.None
18
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, 1997May
20, 2002 under the symbol "BNO.""HNR". Prior to that date it traded under the symbol
"BNO". As of December 31, 2001,2002, there were 34,114,08935,248,296 shares of Common Stockcommon stock
outstanding, heldwith approximately 866 stockholders of record by approximately
947 stockholders.record. The following table
sets forth the high and low sales prices for our Common Stock reported by the
NYSE.
YEAR QUARTER HIGH LOW
- ---- ------- ---- ----
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
2001
First quarter...............................................quarter 2.44 1.56
Second quarter..............................................quarter 2.46 1.55
Third quarter...............................................quarter 1.85 1.00
Fourth quarter..............................................quarter 1.65 1.10
2002
First quarter 4.03 1.43
Second quarter 5.00 3.77
Third quarter 5.43 3.21
Fourth quarter 7.54 5.50
On March 25, 2002,21, 2003, the last sales price for the Common Stockcommon stock as reported by the
NYSE was $4.03$4.40 per share.
Our policy is to retain earnings to support the growth of our business.
Accordingly, our Board of Directors has never declared a cash dividendsdividend on our
Common Stock,common stock and our indenturesindenture currently restrictrestricts the declaration and payment
of any cash dividends.
2519
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, 2001.2002. 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 through our equity affiliates based on a twelve-month period
ending September 30. Accordingly, our results of operations for the years ended
December 31, 2002, 2001, 2000, 1999 and 1998 reflect results from Geoilbent for
the twelve months ended September 30, 2002, 2001, 2000, 1999 and 1998, and from
Arctic Gas (until sold on April 12, 2002) for the twelve months ended September
30, 2002, 2001, 2000, 1999 and 1999.1998.
YEARSYEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
1997
-------- -------- -------- --------- ------------------ ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENTSSTATEMENT OF OPERATIONS:
Total revenues......................... $122,386 $140,284revenues $ 126,731 $ 122,386 $ 140,284 $ 89,060 $ 82,212
$154,033
Operating income (loss)................ 34,585 28,201 53,204 (22,525) (210,066)
51,299
Income (loss) before minority interests............................interests 109,516 42,880 19,08423,044 (34,216) (201,413) 25,202
Net income (loss) per common share:
Basic:
Income (loss) before extraordinary
items...........................Basic $ 1.27 $ 0.54 $ (1.09) $ (6.21) $ 0.62
Extraordinary items............... -- 0.13 -- -- --
-------- -------- -------- --------- --------
Net income (loss).................2.90 $ 1.27 $ 0.67 $ (1.09) $ (6.21)
========= ========== ========== ========== ==========
Diluted $ 0.62
======== ======== ======== ========= ========
Diluted:
Income (loss) before extraordinary
items........................... $ 1.27 $ 0.53 $ (1.09) $ (6.21) $ 0.59
Extraordinary items............... -- 0.13 -- -- --
-------- -------- -------- --------- --------
Net income (loss).................2.78 $ 1.27 $ 0.66 $ (1.09) $ (6.21)
$ 0.59
======== ======== ======== ========= ================== ========== ========== ==========
Weighted average common shares outstanding
Basic................................ 33,967Basic 34,637 33,937 30,724 29,577 29,554
29,119
Diluted..............................Diluted 36,130 34,008 30,890 29,577 29,554 30,834
ATYEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999 1998
1997
-------- -------- -------- --------- ------------------ ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)THOUSANDS)
BALANCE SHEET DATA:
Working capital (deficit).............. $ 97,001 $ (586) $ 12,370 $ 32,093 $ 60,927
$174,759
Total assets...........................assets 335,192 348,151 286,447 276,311 324,363 573,599
Long-term obligations, net of current
position.............................maturities 104,700 221,583 213,000 264,575 280,002
280,016
Stockholders' equity (deficit)(1)(2)... 171,317 67,623 12,904 (17,178) 12,989 197,732
- ---------------
(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 to the equity method.
2620
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
MANAGEMENT, OPERATIONALRISK 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.
OUR CONCENTRATION OF ASSETS IN VENEZUELA INCREASES OUR EXPOSURE TO PRODUCTION
DECLINES AND FINANCIAL RESTRICTIONSDISRUPTIONS. During 2002, the production from the South Monagas
Unit in Venezuela represented all 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 for any reason.
From December 14, 2002 through February 6, 2003, no sales were made because of
PDVSA's inability to accept our oil due to the national civil work stoppage in
Venezuela. As a result, 2002 sales were reduced by approximately 550,000 barrels
and sales in 2003 were reduced by an estimated 1.2 million barrels. While the
situation has stabilized, there continues to be political and economic
uncertainty that could lead to another disruption of our sales. In restoring
production, we encountered problems with some wells, but we do not believe the
associated costs will be material. By the end of March 2003, our average
production was approximately 24,000 barrels of oil per day. As a result of the
national civil work stoppage, the Government of Venezuela terminated several
thousand PDVSA employees and announced a decentralization of PDVSA's operations.
While the effect of these changes cannot be predicted, it could adversely affect
PDVSA's ability to manage its contracts and meet its obligations with its
suppliers and vendors, such as Benton-Vinccler. As a result of the situation in
PDVSA, its payment to Benton-Vinccler for crude delivered in the fourth quarter
2002 was late by seven days. We believe that the payment demonstrates PDVSA's
commitment to building its production levels back to full capacity and returning
to more normalized business relations with its customers and suppliers. While we
have substantial cash reserves to withstand a future disruption, a prolonged
loss of sales or a failure or delay by PDVSA to pay our invoices could have a
material adverse effect on our financial condition. We have takenbeen required to
curtail sales to PDVSA in April and December 2002 due to insufficient crude oil
storage capacity. We have never been required to curtail sales before 2002. We
cannot be assured that our sales to PDVSA will not be curtailed in the necessary stepsfuture in
the same manner.
GEOILBENT'S LIQUIDITY COULD LIMIT ITS ABILITY TO MAINTAIN OR INCREASE
PRODUCTION.
ABILITY TO COMPLY WITH CREDIT FACILITY. The $50 million revolving credit
agreement with EBRD requires that Geoilbent meet certain covenants which
include, among other things, the maintenance of financial ratios. If Geoilbent
fails to strengthenmeet the ratio requirements for two consecutive quarters it will result
in an event of default whereby EBRD may, at its option, demand payment of the
outstanding principal and interest. In addition, the loan agreement requires
that Geoilbent implement a new management enhanceinformation system by May 1, 2003. If
Geoilbent is unable to timely satisfy this requirement, it also results in an
event of default whereby EBRD may, at its option, demand payment of the
outstanding principal and interest. Any event of default also gives EBRD the
right to exercise its security interest in the assets of Geoilbent and, under a
share pledge agreement, our
financial flexibility, and improve our operations. In 2001, we completed the
following:
- installed new senior management;
- redefined our strategic priorities to focus on value creation;
- initiated capital conservation steps and financial transactions,
including the Proposed Arctic Gas Sale, designed to de-leverage the
Company and improve our cash flow for reinvestment;
- undertook a comprehensive study of our core Venezuelan asset, which
focused on enhancing the value of its production;
- pursued additional financing to accelerate the commercial development of
our Russian assets;
- built the Tucupita pipeline in Venezuela to reduce transportation costs;
- sought and obtained relief from certain restrictive provisions of our
debt instruments;
- reduced our corporate overhead, moved our headquarters to Houston and
transferred engineering, geological and geophysical activities to its
overseas offices; and
- proposed a change in our name to Harvest Natural Resources, Inc.
We continue to explore means by which to maximize stockholder value.
On February 27, 2002, we entered into a Sale and Purchase Agreement
("Proposed Arctic Gas Sale") to sell our entire 68 percent stock ownership interest in Arctic Gas CompanyGeoilbent. An event of default
could also limit Geoilbent's ability to a nominee ofaccess additional funds under the Yukos Oil Company for $190
million. We will also receive approximately $30 million as repayment of
intercompany loans owed to us by Arctic Gas. We intend to use a portion of the
net proceeds to retire all of the $108 million outstanding 11 5/8 percent senior
notes in accordance with their terms. We intend to use any remaining net
proceeds and cash received from the repayment of loans to further reduce debt
from time to time, accelerate the strategic growth of its assets in Venezuela
and Russia and for general corporate purposes. On March 22, 2002, we were
notifiedEBRD
facility. It is unlikely that the Transaction had received the requisite consents from the
Russian Ministry for Antimonopoly Policy and Support for Entrepreneurship. On
March 28, 2002, we received the first payment ($120.0 million) of the Proposed
Arctic Gas Sale proceeds. However, in the event that the Transaction does not
close, weGeoilbent will be able to timely implement a new
management information system as required by the EBRD loan facility. Further,
while on March 12, 2003, Geoilbent has drawn down $8 million on the EBRD
facility to review additional strategic alternativesmeet its current liabilities, there can be no assurance that
Geoilbent will be able to repaymeet the $108 millioncurrent ratio requirement on March 31, 2003.
As a result of 11 5/8 percent senior notesthese events Geoilbent's independent accountants have indicated
in their report that substantial doubt exists regarding Geoilbent's ability to
meet its debts as they come due in May 2003, including, but
not limited to, selling all or part of our existing assets in Venezuela and Russia, restructuring our debt, some combination thereof, or the selling of the
Company. However,continue as a going concern. While no
assurance can be given, that anythe Company believes these covenant defaults are
temporary and does not result in an other than temporary decline in the
Company's investment in Geoilbent or will cause EBRD to declare a default after
considering Geoilbent's historical net income, cash flow from operating
activities and other matters.
ABILITY TO REPAY ACCOUNTS PAYABLE. At September 30, 2002, and September 30,
2001, the current liabilities of these steps can be
successfully completed or that we ultimately will determine that any of the
steps should be taken. The Pro Forma adjustments reflect a net gain after tax of
$92.0Geoilbent exceeded its current assets by $35.3
million which utilizes our $136.0and $25.0 million, net operating loss. The cash
available after tax is used to purchase the $108.0 million 11 5/8 percent senior
notes at par.
In the event the Proposed Arctic Gas Sale closes, the Supplemental
Unaudited Pro Forma Condensed Balance Sheetrespectively. Included in current liabilities as of
September 30, 2002 are loans repayable to EBRD ($22.0 million) and IMB ($0.6
million). The IMB liability was repaid in November 2002. This debt has been
classified as current because of Geoilbent's status under the
21
EBRD loan. At December 31, 2001 shown below
illustrates the impact to the Company.
27
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL UNAUDITED PRO FORMA CONDENSED BALANCE SHEET
AS OF
DECEMBER 31, PRO FORMA
2001 ADJUSTMENTS(1) PRO FORMA
------------ -------------- ---------
(AMOUNTS IN THOUSANDS)
ASSETS:
Cash............................................ $ 9,024 $ 82,587 $ 91,611
Investment in Arctic Gas........................ 24,405 (24,405) --
Intercompany Receivable......................... 28,829 (28,829) --
Deferred Tax Asset.............................. 57,700 (44,398) 13,302
Other Assets.................................... 228,193 228,193
-------- --------
Total................................. $348,151 $333,106
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY:
Liabilities..................................... $ 58,945 $ 58,945
Long-Term Debt.................................. 221,583 (108,000) 113,583
Total Stockholders' Equity...................... 67,623 92,955 160,578
-------- --------
Total................................. $348,151 $333,106
======== ========
Debt to Total Equity............................ 77% 41%
- ---------------
(1) To record gain on sale2002, Geoilbent had accounts payable outstanding of
68 percent interest in Arctic Gas Company, to
repay intercompany debt and to repay $108 million of 11 5/8 percent senior
notes.
SEE NOTE 16 TO THE AUDITED FINANCIAL STATEMENTS IN ITEM 14 -- EXHIBITS,
FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
As part of the Proposed Arctic Gas Sale, we have arranged a credit facility
of up to $100 million for Arctic Gas. In the event that the Proposed Arctic Gas
Sale does not close, we will request Arctic Gas to immediately repay this
facility.
We possess significant producing properties in Venezuela, which we believe
have yet to be optimized, and valuable unexploited acreage in both Venezuela and
Russia. We believe the eleven new wells drilled in the South Tarasovskoye Field
since July 2001 may significantly increase the value of our Geoilbent
properties. In December 2001 and January 2002, we spudded the first two wells in
our seven well Tucupita field program in Venezuela. We are evaluating the
construction of additional processing and handling facilities and are in
discussions with PDVSA to negotiate a sales contract that will allow for the
first-time sale of natural gas in Venezuela by our affiliate.
In May 2001, we initiated a process intended to effectively extend the
maturity of the senior notes due May 1, 2003 by exchanging new 13.125 percent
senior notes due December 2007 plus warrants to purchase shares of our common
stock for each of the 2003 Notes. The exchange offer was withdrawn in July 2001.
However, in August 2001, we solicited and received the requisite consents from
the holders of both the 2003 Notes and the 2007 Notes to amend certain covenants
in the indentures governing the notes to enable Arctic Gas Company to incur
nonrecourse debt of up to $77 million to fund its oil and gas development
program. As an incentive to consent, we paid each noteholder an amount in cash
equal to $2.50 per $1,000 principal amount of notes held for which executed
consents were received. The total amount of consent fees paid to the consenting
noteholders was $0.3 million, which has been included in general and
administrative expenses.
In June 2001, we implemented a plan designed to reduce overall general and
administrative costs, including exploration overhead, at our corporate
headquarters and to transfer management oversight of geological and geophysical
activities to our overseas offices in Maturin, Venezuela and in Western Siberia
and
28
Moscow, Russia. The reduction in general and administrative costs was
accomplished by reducing our headquarters staff and relocating our headquarters
to Houston, Texas from Carpinteria, California. For 2001, we recorded
non-recurring items of $11.4 million, $5.7$12.2 million of which are included in
general and administrative expenses, $1.7approximately $5.9 million of which are included in
depletion, depreciation and amortization, $3.2 million in operating expenses and
$0.8 million in taxes other than income.was 90 days or more past due.
The general and administrative expenses
include $2.2 million on the failed debt exchange, $2.2 million for severance and
termination benefits for 33 employees, $1.1 million for lease relinquishment
expenses, and $0.2 million for relocation costs to Houston. Depletion,
depreciation and amortization included $0.9 million for the reduction in the
carrying value of fixed assets thatamounts outstanding were not transferred to Houston and $0.8
million loss on subleasing the former Carpinteria headquarters. All expenses
were paid by December 31, 2001.
Geoilbent has reduced its 2002 capital budget to approximately $16.6
million, of which $2.7 million is for the North Gubkinskoye Field, $9.7 million
is for the South Tarakovskoye Field, $2.2 million is to carry out seismic and
related exploration activity and $2.0 million is for natural gas plant economic,
technical and feasibility studies. Geoilbent's 2002 operating budget includes
$16 million for principal payments on the loan facility. In addition, Geoilbent
had outstanding accounts payable of $26.6 million as of December 31, 2001, primarily to contractors and vendors for drilling
and construction services. AlthoughUnder Russian law, creditors, to whom payments are 90
days or more past due, can force a company into involuntary bankruptcy. We
believe most of the significantly overdue payables have now been paid as a
result of the $8 million draw down of the EBRD facility.
ABILITY TO REPAY OUR LOAN. As of September 30, 2002, the Geoilbent shareholders
had provided Geoilbent with subordinated loans totaling $7.5 million ($2.5
million from Harvest and $5.0 million from Minley). These loans are unsecured
and repayable commencing in January 2004. Our interest rate is based on LIBOR up
to January 2004, and rises from 8 to 12 percent thereafter. There can be no
assurance that Geoilbent will have the ability to repay the loan made by the
Company when due.
ABILITY TO MAINTAIN OR INCREASE PRODUCTION. Because of Geoilbent's reducedsignificant
working capital expenditure budget may helpdeficit, a substantial portion of its cash flow must be utilized
to alleviate any shortfallreduce accounts and taxes payable. Additionally, in order to maintain or
increase proved oil and gas reserves, Geoilbent must make substantial capital
expenditures in 2003. Geoilbent's net cash provided by operating activities is
dependent on the level of funds available to make payments tooil prices, which are historically volatile and are
significantly impacted by the banks andproportion of production that Geoilbent can sell
on the export market. Historically, Geoilbent has supplemented its
creditors as those payments come due, it is uncertain that Geoilbent's cash flow
from operations will be sufficientwith additional borrowings or equity capital. Should oil prices
decline for a prolonged period, or if Geoilbent is unable to do so, and it may be necessary for
Geoilbentaccess the EBRD
facility or the shareholders are unwilling to obtainmake capital contributions, fromthen
Geoilbent would need to reduce its partners, including the
Company,capital expenditures, which could limit its
ability to have sufficient funds to make these payments on a timely basis.maintain or increase production and, in turn, meet its debt service
requirements. Although the Company may consider making such a capital contribution,
there can be no assurances that the Company will do so, nor can there be any
assurances that Geoilbent's other partnershareholder will be willing or able to do so.
Under Russian
law,Asset sales and financing are restricted under the terms of the EBRD loan.
OUR MINORITY INTEREST IN GEOILBENT MAY LIMIT OUR ABILITY TO INFLUENCE CHANGE. We
own 34 percent in Geoilbent. We are reviewing ways to improve operations, such
as the secondment of expatriate employees or consultants, the upgrading of
drilling equipment, improved operating techniques and economic decision making,
but we are a creditor can forceminority partner and therefore may not be able to fully influence
changes in the operations.
OUR OPERATIONS IN AREAS OUTSIDE THE U.S. ARE SUBJECT TO VARIOUS RISKS INHERENT
IN FOREIGN OPERATIONS, AND OUR STRATEGY TO FOCUS ON VENEZUELA AND RUSSIA LIMITS
OUR COUNTRY RISK DIVERSIFICATION. 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 company into involuntary bankruptcy ifresult
of hazards such as expropriation, war, insurrection, civil unrest, strikes 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 our international operations. Our international
operations may also be adversely affected by laws and policies of the company's
payments have been due for more than 90 days.
AtUnited
States affecting foreign trade, taxation and the annual meetingpossibility of our shareholdershaving to be
heldsubject to exclusive jurisdiction of courts in connection with legal disputes
and the possible inability to subject foreign persons to the jurisdiction of the
courts in the United States. Our strategy to focus on May 14, 2002, our
stockholders will vote on a proposal to change the name of our company to
"Harvest Natural Resources, Inc."
OPERATING STRATEGY
Our business strategy supports the steady investment, prudent risk
management and timely harvest of large hydrocarbon resources for attractive
values. For the foreseeable future, we believe our best success will be found in Venezuela and Russia
areas in which we have significant experienceconcentrates our foreign operations risk and expertise.
During 2001, our operating strategy was necessarily focused on improvingincreases the efficiency and efficaciespotential impact to
us of our current operations in both Venezuela and
Russia. Over the years, we have benefited from the significant capital
commitment made to these areas, but have suffered financially from sub-optimal
operating, contracting and risk management practices which, for the most part,
have been or are currently in the process of being significantly improved. In
Venezuela, we implemented new development and production plans at Benton-
Vinccler following an eight-month suspension of drilling and an extensive
reservoir study, which resulted in increased production, lower operating costs,
and added confidence in our future drilling plans to extend the life and value
of the field. We have also streamlined decision making, improved internal
controls and implemented industry standard techniques to mitigate geologic, operating, financial and political risks attendant with doing business in Venezuela.those countries.
OUR FOREIGN OPERATIONS EXPOSE US TO FOREIGN CURRENCY RISK. Our principal
operations are in Venezuela and Russia which have historically been considered
highly inflationary economies. Results of operations in those countries are
re-measured in United States dollars, and all currency gains or losses are
recorded in the consolidated statement of operations. 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. Our Venezuelan receipts are denominated in U.S. dollars, and
most expenditures are in U.S. dollars as well. For a discussion of currency
controls in Venezuela, see CAPITAL RESOURCES AND LIQUIDITY below.
22
NEW YORK STOCK EXCHANGE DELISTING. In Russia, whereOctober 2001, we arereceived a minority holder in Geoilbent,letter from
the New York Stock Exchange ("NYSE") notifying us that we are attemptinghad fallen below the
continued listing standard of the NYSE. These standards include a total market
capitalization of at least $50 million over a 30-day trading period and
stockholders' equity of at least $50 million. According to pursue a similar course,the NYSE's notice,
our total market capitalization over the 30 trading days ended October 17, 2001
was $48.2 million and our stockholders' equity was $16.0 million as of September
30, 2001. In accordance with the help of other interest owners, in orderNYSE's rules, we submitted a plan to improve operations and extend the lifeNYSE
detailing how we expected to reestablish compliance with the listing criteria
within the next 18 months. In January 2002, the NYSE accepted our business plan,
subject to quarterly reviews of the field, lower operating costsgoals and enhance financial results. These assets representobjectives outlined in that plan.
By April 2002, the total market capitalization and stockholder's equity
deficiencies were eliminated, and as of December 31, 2002, we remained in
compliance with NYSE listing standards.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS. As of December 31, 2002, our
long-term debt was $104.7 million. Our long-term debt represented 38 percent of
our debt to total capital at December 31, 2002. Our current cash balances lessen
the impact of our debt but it can effect our operations in several important
ways, including the following:
o a significant potential value
for us, but remain subjectportion of our cash flow from operations is used to
sub-optimal operating conditions whilepay interest on borrowings;
o the covenants contained in the indentures governing our lack of
majority control over its operations could inhibitdebt limit
our ability to implement
necessaryborrow additional funds or to dispose of assets;
o the covenants contained in the indentures governing our debt affect
our flexibility in planning for, and reacting to, changes in
management, operationsbusiness conditions;
o the level of debt could impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or financing matters.other purposes; and
o the terms of the indentures governing our debt permit our creditors
to accelerate payments upon an event of default or a change of
control.
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 to $13.08 per Bbl for the year ended
December 31, 2002, compared to $12.52 per Bbl for the year ended December 31,
2001. 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:
o relatively minor changes in the supply of and demand for oil;
o market uncertainty;
o the level of consumer product demand;
o weather conditions;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political and economic conditions in oil-producing countries; and
o overall economic conditions.
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. No ceiling test write-downs were
required in 2002.
23
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, 2002, approximately 46 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 demand, our ability to
produce, or in governmental regulations or taxation will also affect actual
future net cash flows. The timing of both Venezuelathe production and Russia, and in other counties around the world,expenses from
the development and production of local marketsoil 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 representsindustry in general will
affect the accuracy of the 10 percent discount factor.
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 uncertain. Oil and natural gas drilling and production
activities may be shortened, delayed or canceled as a significant
opportunityresult of a variety of
factors, many of which are beyond our control. These factors include:
24
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o weather conditions;
o shortages in experienced labor;
o shortages or delays in the delivery of equipment; and
o delays in receipt of permits or access to lands.
The prevailing price of oil also affects the cost of and the demand for
us. However,drilling rigs, production equipment and related services. We cannot assure you
that the developmentnew 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 markets,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. The events of September 11, 2001 forced changes to our
insurance coverage. Acts of terrorism are "excluded risks" from our property
insurance coverage. We cannot assure you that our insurance will be adequate to
cover losses or liabilities. We cannot predict the continued availability of
insurance at premium levels that justify its purchase.
COMPETITION WITHIN THE INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS. We operate
in large part,
depends upon substantial capital investment by third parties in the
infrastructure needed to produce,
29
gather, treat, transport, storea highly competitive environment. We compete with major and convertindependent oil
and natural gas into marketable
products. While this investment is beginningcompanies for the acquisition of desirable oil and gas
properties and the equipment and labor required to materialize in manydevelop and operate such
properties. Many of these markets, it will take many years,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 some instances,response to place such assets into
service.economic or political conditions.
Matters regulated may 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 or limit supplies of oil and natural gas, these
agencies have restricted the rates of flow of oil and natural gas wells below
actual production capacity. We are well positionedcannot predict the ultimate cost of compliance
with these requirements or their effect on our operations.
2002 FINANCIAL AND OPERATIONAL PERFORMANCE
We had two overriding strategic priorities for 2002: (i) to benefit fromreduce the
emergenceamount of new regional
gas markets in proximitydebt on the balance sheet; and (ii) to our reserves.
Our long-term strategy is to identify, access and exploit large resources
of hydrocarbons in underexploited areas aroundimprove the world that can be developed
at low overall finding costs, produced at low operating costs and converted into
proved reserves, production and value. While our success is dependent upon many
factors both within and outsidevalue of our
control,producing assets. We also strengthened our management team and recommitted, as a
management team and board of directors, to maintain the highest standards in
ordercorporate governance, financial transparency and business ethics. In May 2002,
the shareholders approved our name change to achieve this
strategy,Harvest Natural Resources, Inc. In
September 2002, our board of directors authorized the repurchase of up to one
million shares of our common stock. As of March 11, 2003, we must:
- continuehave repurchased
approximately 80,000 shares for an aggregate price of $0.4 million.
The balance sheet was significantly strengthened by completing the sale
of Arctic Gas which produced $220 million in cash and net proceeds, after taxes
and expenses, of $190 million (including $30 million for repayment of our
intercompany debt) and were used, in part, to redeem all of the $108 million of
11.625 percent senior notes due in May 2003. An additional $20 million of the
$105 million of 9.375 percent senior notes due in November 2007 were also
retired. The balance of the proceeds were retained to improve our financial
flexibility and financing strategies;
- exploitto be available
25
for acquisitions, reduction of debt or other general corporate purposes. This
strategy has already been partially rewarded by our core assetsability to maintain our
financial flexibility in Venezuelaspite of the loss of production temporarily as a result
of the national civil work stoppage in Venezuela. At December 31, 2002, we had
$91.9 million of cash or marketable securities and Russia;a debt to total capital ratio
of 38 percent compared with over 77 percent at the end of 2001.
We also improved the value of our production, an equally important
second priority. We have lowered the cash costs (lease operating, general and
- seek and exploit new oil andadministrative) of our produced barrel by 19 percent year-on-year to
approximately $5.20 per barrel, increasing unit profitability. We also
successfully negotiated a contract to sell 198 Bcf of natural gas resources in our core areas.
We intend to continuePDVSA over
the next 10 years. Establishing a market for this gas allowed us to seek and exploit new oil and natural gasrecord an
additional 26 net MMBOE of reserves in 2002.
In 2002, Geoilbent, in which we have a 34% interest, was able to
improve production. Geoilbent increased production by 33 percent to 7 million
barrels per year and has begun restructuring its balance sheet, by converting
the loan with EBRD into a $50 million revolving line of credit. Subject to
availability, this credit facility will allow Geoilbent to reduce its current
areasliabilities and accelerate the development of interest while working toward minimizing the associated
financialSouth Tarasovskoye oil field
in western Siberia. However, as discussed above under Geoilbent Liquidity,
significant issues exist over Geoilbent continuing as a going concern.
2003 CAPITAL PROGRAM
Benton-Vinccler's capital expenditures for 2003 are projected to be $45
to $50 million, compared with 2002 capital expenditures of $43 million. To
partially fund its capital program, Benton-Vinccler borrowed $15.5 million in
October 2002 for the construction of the pipeline and operating risks. To reduce these risks, not onlyrelated facilities to
deliver gas to PDVSA. Benton-Vinccler has also hedged a portion of its 2003 oil
production by purchasing a WTI crude oil "put" to protect part of its 2003 cash
flow.
In January 2003, we completed our Tucupita Field development program
in seeking new
reserves, butVenezuela. In 2003, Benton-Vinccler plans to drill three oil wells in the
Bombal Field and construct a pipeline from Bombal to the Tucupita delivery line.
Benton-Vinccler also with respectplans to our existing operations, we:
- Focus Our Effortsconvert two gas injection wells in Areas of Low Geologic Risk: We intendUracoa to focus our
explorationgas
production. Other capital projects relate to the gas project and development activities onlyfacilities
improvements.
Geoilbent's capital expenditures for 2003 are projected to be
approximately $20 million. In 2003, Geoilbent plans to drill up to eighteen
wells in areas of known, proven
hydrocarbons.
- 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 experienceSouth Tarasovskoye and to minimize costs. In pursuing new
opportunities, wecommence a comprehensive work over program in
North Gubkinskoye. An appraisal well is planned in 2003 to delineate a potential
south extension of the South Tarasovskoye field that will seekbe developed with
further drilling if successful. Geoilbent expects to enter at an early stagefund the South Tarasovskoye
drilling program through draw downs from the EBRD loan facility. For a
description of the EBRD loan agreement and find local
investment partners in an effort to reduce our risk in any one venture.a discussion of Geoilbent's
compliance with the covenants and possible liquidity problems, see Geoilbent's
Liquidity above and Note 9 - 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, as well as maximize the amount of local
financing capacity to develop the hydrocarbons and associated
infrastructure.Russian Operations.
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 for the year ended December 31, 2002, reflect the
results of Geoilbent and Arctic Gas (until sold on April 12, 2002) for the
twelve months ended September 30, 2002, 2001 2000 and 1999.2000.
You should read the following discussion of the results of operations
for each of the years in the three yearthree-year period ended December 31, 20012002 and the
financial condition as of December 31, 20012002 and 20002001 in conjunction with our
Consolidated Financial Statements and related Notes thereto.
26
We have presented selected expense items from our consolidated income
statement as a percentage of crude oil and natural gas sales in the following table:
YEARS ENDED DECEMBER 31,
-------------------------------------------
2002 2001 2000 1999
---- ---- ----
Operating Expenses(1)....................................... 32%Expenses 27% 35% 34% 44%
Depletion, Depreciation and Amortization(2)................. 19Amortization 21 21 12 19
General and Administrative(3)...............................Administrative 13 16 12 12 29
Taxes Other Than on Income(4)...............................Income 3 4 3
4
Interest....................................................Interest 13 20 21 33
30
- ---------------YEARS ENDED DECEMBER 31, 2002 AND 2001
non-recurring costs excluded in millions:
(1) $3.2 in natural gas fuel use chargesNet income for the year ended December 31, 2002 was $100.4 million, or
$2.78 per diluted share, compared with $43.2 million for the same period last
year. The $100.4 million net income included the after-tax gain from the Arctic
Gas Sale of 1997 through 2000$93.6 million, and the pre-tax $3.3 million, partial recovery of a
bad debt related to A. E. Benton (See Note 13 - Related Party Transactions);
offset, in part, by a pre-tax $13.4 million impairment of the WAB-21 petroleum
property located in the South China Sea. Operating and general and
administrative expenses were reduced by $12 million, or almost 20 percent
compared with 2001.
Our results of operations for the year ended December 31, 2002
primarily reflected the results for Benton-Vinccler in Venezuela, which
accounted for 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 3.8 percent higher in 2002
compared with 2001. Realized fees per barrel increased 4.5 percent (from $12.52
in 2001 to $13.08 in 2002).
Our revenues increased $4.6 million, or 3.6 percent, during the year
ended December 31, 2002, compared with 2001. 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, 2002 from Venezuela were 9.7 MMBbls compared to 9.8 MMBbls
for the year ended December 31, 2001. The decrease in sales quantities of
100,000 Bbls, or less than 1 percent, was due primarily to logistics and
equipment delays in early 2002 at the Tucupita field and the national civil work
stoppage which led to the shut-in of our production in late December 2002 for
nine days. Average production for the year decreased by less than 775 Bbls per
day for the aforementioned reasons.
Our operating expenses decreased $8.8 million, or 21 percent, for the
year ended December 31, 2002, compared with the year ended December 31, 2001.
Lower fuel gas, water and oil treatments accounted for $3.4 million of the
reduction. Reduced workover expense ($2.6 million) and lower expenses associated
with the transportation of Tucupita oil ($5.0 million) with the completion of
the Tucupita oil pipeline in late 2001 were offset by $1.1 million of increases
in various other categories. Depletion, depreciation and amortization increased
$0.8 million, or 4 percent, during the year ended December 31, 2002, compared
with 2001 primarily due to the first three quarters of 2002 having been
calculated on the lower beginning of the year reserves. We added 198 Bcf or 33
MMBOE in the fourth quarter which will impact this calculation prospectively.
Depletion expense per barrel of oil produced from Venezuela during 2002 was
$2.57 compared with $2.26 during 2001 primarily due to future development costs.
We recognized write-downs of capitalized costs of $13.4 million associated with
WAB-21 offshore China and $1.1 million for the Lakeside Prospect exploration
activities during the year ended December 31, 2002, compared with $0.5 million
associated with final costs associated with prior exploration activities.
General and administrative expenses decreased $3.6 million from 2001 to 2002.
The move to Houston was completed in 2001 and overall staff levels were reduced
to the current level of ten in Houston. We recognized $3.3 million of income for
the partial recovery of prior year bad debt allowance for the funds received
from the A.E. Benton bankruptcy. The consideration includes 600,000 shares of
stock taken into treasury at a price of $3.56 per share and approximately $1.1
million in cash.
Taxes other than on income decreased $1.3 million, or 24 percent,
during the year ended December 31, 2002, compared with 2001. This was primarily
due to decreased Venezuelan municipal taxes and a one-time adjustment of U.S.
employment taxes of $0.7 million.
27
Investment income and other decreased $1.0 million, or 33 percent,
during the year ended December 31, 2002, compared with 2001. This was due to
lower interest rates earned on average cash and marketable securities balances.
Interest expense decreased $8.6 million, or 34 percent, during the year ended
December 31, 2002, compared with 2001. We redeemed all $105 million of our
11.625 percent Senior Notes due in May 2003 and purchased $20 million face of
the 9.375 percent Senior Notes due in November 2007. In October 2002, we
borrowed under a $15.5 million loan to finance the construction of the gas
pipeline in Venezuela from the Uracoa field to the PDVSA sales line.
Net gain on exchange rates increased $3.8 million, or 493 percent for
the year ended December 31, 2002, compared with 2001. This was due to the
significant devaluation of the Bolivar. We realized income before Venezuelan taxincome taxes
and minority interest is included.
(2) $1.7 reductionof $169.8 million during the year ended December 31, 2002,
compared with $7.2 million in carrying value2001. The increase was dominated by the Arctic Gas
Sale. The 2001 income tax benefit related to the potential utilization by the
Arctic Gas Sale of California office lease.
(3) $2.3net operating loss carry forwards in debt exchange costs; $1.1 California office lease relinquishment;
$0.2 relocation2002. The effective tax
rate of 36 percent reflects the approximate rate for Venezuela and no tax
benefits are being recognized for expenses incurred in the U.S. The income
attributable to Houston; $2.1 severancethe minority interest increased $3.8 million for the year ended
December 31, 2002, compared with 2001. This was primarily due to the increased
profitability (oil prices) and termination payments.
(4) $0.8reduced expenses of Benton-Vinccler.
Equity in municipal tax adjustments before Venezuelan taxnet earnings of affiliated companies decreased $5.7 million,
during the year ended December 31, 2002, compared with 2001. This was primarily
due to the decreased income from Geoilbent and minority
interest.the elimination of Arctic Gas
equity income on April 12, 2002, the date of its sale. Geoilbent's equity income
declined from $7.0 million in 2001 to $1.6 million in 2002. We recorded equity
in net losses of Arctic Gas in both years. Revenues from Geoilbent were $31.0
million for the year ended September 30, 2002, compared with $34.4 million for
2001. The decrease of $3.3 million, or 10 percent, was due to lower Russian
domestic crude oil prices offset by higher sales quantities. Prices for
Geoilbent's export crude oil averaged $21.73 per Bbl and its domestic crude oil
averaged $8.89 during the year ended September 30, 2002, compared with $20.48
per Bbl for export crude oil and $13.69 for domestic for the year ended
September 30, 2001. Our share of Geoilbent oil sales quantities increased by
587,102 Bbls, or 33 percent, from 1,762,814 Bbls sold during the year ended
September 30, 2001, to 2,349,916 Bbls sold during the year ended September 30,
2002.
YEARS ENDED DECEMBER 31, 2001 AND 2000
Our results of operations for the year ended December 31, 2001
primarily reflected the reversal of our tax valuation allowance and results for
Benton-Vinccler C.A. in Venezuela, which accounted for all of our production and oil
sales revenue. As a result of decreases in world crude oil prices, partially
offset by higher production from the South Monagas Unit, oil sales in Venezuela
were 13 percent lower in 2001 compared with 2000. Realized fees per barrel
decreased 16 percent (from $14.94 in 2000 to $12.52 in 2001) and oil sales
quantities increased 4 percent (from 9.4 MMBbls of oil in 2000 to 9.8 MMBbls of
oil in 2001). Our operating expenses from the South Monagas Unit decreased by 14
percent due to decreased workover costs and completion of the 31-mile oil
pipeline in the fourth quarter of 2001 to transport oil from the Tucupita field
to the central processing unit in the Uracoa field.
Our revenues decreased $17.9 million, or 13 percent, during the year
ended December 31, 2001 compared with 2000. This was due to decreased oil sales
revenue in Venezuela as a result of decreases in world crude oil prices,
partially offset by higher sales quantities. Our sales quantities for the year
ended December 31, 2001 from Venezuela were 9.8 MMBbls compared to 9.4 MMBbls
for the year ended December 31, 2000. The increase in sales quantities of
413,428 Bbls, or 4 percent, was due primarily to production efficiency and
reservoir management at Uracoa, and enhanced drilling performance for the eight
wells drilled in the Uracoa field beginning August 31, 2001 as a result of
incorporating information from the field simulation study conducted during the
first eight months of 2001. Production increased to 28,000 Bbls or oil per day
by the end of 2001 as a result of drilling 8 additional wells during the year.
Prices for crude oil averaged $12.52 per Bbl (pursuant to terms of an operating
service agreement) from Venezuela compared with $14.94 per Bbl for 2000.
Our operating expenses decreased $4.7 million, or 10 percent, which
included a fuel gas charge of $3.2 million, during the year ended December 31,
2001 compared to the year ended December 31, 2000. The fuel gas charge related
to a dispute regarding a difference between rates we paid and rates claimed by
PDVSA for natural gas used as fuel for the period 1997 through 2000. Depletion,
depreciation and amortization increased $8.3 million, or 48 percent, during the
year ended December 31, 2001 compared with 2000 primarily due to decreased
proved reserves. Depletion expense per barrel of oil produced from Venezuela
during 2001 was $2.26 compared with $1.68 during 2000 as a result of a
28
decrease in proved reserves. We recognized write-downs of capitalized costs of
$0.5 million associated with exploration activities during the year ended
December 31, 2001 compared with $1.3 million associated with exploration
activities in California. General and administrative expenses decreased $2.3
million from $16.7 million in 2000 to $14.4 million in 2001, exclusive of $5.7
million of non-recurring costs. Non-recurring general and administrative costs
are comprised of $2.3 million in debt exchange cost, $1.1 million in California
lease relinquishment, $0.2 million relocation costs to Houston and $2.1 million
severance and termination payments paid or accrued in 2001.
Taxes other than on income increased $1.0 million, or 22 percent,
during the year ended December 31, 2001 compared with 2000. This was primarily
due to increased Venezuelan municipal taxes.
Investment income and other decreased $5.5 million, or 64 percent,
during the year ended December 31, 2001 compared with 2000. This was due to
lower average cash and marketable securities balances. Interest expense
decreased $4.1 million, or 14 percent, during the year ended December 31, 2001
compared with 2000. This was primarily due to the reduction of debt balances,
partially offset by a reduction of capitalized interest expense. Net gain on
exchange rates increased $0.4 million, or 136 percent for the year ended
December 31, 31
2001 compared with 2000. This was due to changes in the value of
the Bolivar. We realized income before income taxes and minority interest of
$7.2 million during the year ended December 31, 2001 compared with $33.1 million
in 2000. The negative effective tax rate varies from the U.S. statutory rate of
35 percent primarily because of the reversal of a U.S. tax valuation allowance.
The reversal related to the potential utilization of net operating loss carry
forwards. We have determined that it is more likely than not that these U.S.
deferred tax assets will be realized in 2002. See Note 16 to the Audited
Financial Statements in Item 14 -- Exhibits, Financial Statement Schedules and
Reports on Form 8-K. The income attributable to the
minority interest decreased $2.3 million for the year ended December 31, 2001
compared with 2000. This was primarily due to the decreased profitability (oil
prices) of Benton-Vinccler.
Equity in net earnings of affiliated companies increased $0.6 million,
or 11 percent, during the year ended December 31, 2001 compared with 2000. This
was primarily due to the increased income from Geoilbent. Our share of revenues
from Geoilbent was $34.4 million for the year ended September 30, 2001 compared
with revenues of $26.8 million for 2000. The increase of $7.6 million, or 27
percent, was due to higher world crude oil prices and higher sales quantities.
Prices for Geoilbent's crude oil averaged $19.51 per Bbl during the year ended
September 30, 2001 compared with $18.54 per Bbl for the year ended September 30,
2000. Our share of Geoilbent oil sales quantities increased by 318,633 Bbls, or
22 percent, from 1,444,181 Bbls sold during the year ended September 30, 2000 to
1,762,814 Bbls sold during the year ended September 30, 2001.
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:
-o drilling and completion costs of wells and the cost of production,
treating and transportation facilities;
-o geological, geophysical and seismic costs; and
-o 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,In 2002,
Benton-Vinccler instituted a hedging program to establish a crude oil price
floor using a WTI costless collar for our Tucupita development drilling program.
Benton-Vinccler has also hedged a portion of its 2003 oil sales by purchasing a
WTI crude oil "put" to protect its 2003 cash flow. The put is for 10,000 barrels
of oil per day for the period of March 1, 2003 through December 31, 2003. Due to
the pricing structure for our Venezuela oil, the put has the economic effect of
hedging approximately 20,000 Bopd. The put costing $2.50 per barrel, or
approximately $7.7 million, has a strike price of $30.00 per barrel.
In February 2002, the Venezuelan Bolivar was allowed to float against
the U.S. dollar. On February 5, 2003, the Venezuelan government imposed currency
controls and created the Commission for Administration of Foreign Currency
("CADIVI") with the task of establishing the detailed rules and regulations and
generally administering the exchange control regime. The currency controls fix
the exchange rate between the Bolivar and the U.S. dollar, and restricts the
ability to exchange Bolivars for dollars and vice versa. Oil companies, such as
Benton-Vinccler are allowed to receive payments for oil sales in U.S. currency
and pay dollar-denominated expenses from those payments. We are
29
unable to predict the full impact of the currency controls on us or
Benton-Vinccler as the CADIVI has not issued final regulations. The near-term
effect has been to restrict Benton-Vinccler's ability to make payments to
employees and vendors in Bolivars, causing it to borrow money on a short-term
basis to meet these obligations. All of these short-term borrowings have been
repaid and while we now have Bolivars to meet our current obligations, the
situation could change. In addition, the currency controls have increased the
cost of Benton-Vinccler's Bolivar denominated debt. Benton-Vinccler has provided
the thirty day notice of its intention to repay its Bolivar denominated debt.
The full amount will be repaid on March 31, 2003. As of February 24, 2003, we
have cash reserves of approximately $75 million and do not expect the currency
conversion restriction to adversely affect our ability to meet our short-term
loan obligations.
Our ability to pay interest on our debt and general corporate overhead
is dependent upon the ability of Benton-Vinccler to make loan repayments,
dividends and other cash payments to us; however,us. However, there have been, and may again
be, unforeseeable interruptions in oil and gas sales or there may be contractual
obligations or legal impediments such as the recently instituted currency
controls to receiving dividends or distributions from Benton-Vinccler, which
could prohibit Benton-Vinccler from remitting funds to us. Management does not
believe that the currency controls will prohibit our subsidiaries.ability to receive funds
from Benton-Vinccler, although were it to do so, our ability to meet our cash
requirements would be adversely affected.
Debt Reduction and Restructuring Program.Reduction. We currently have a significant debt principal obligationsobligation
payable in 2003 ($108 million) and 2007 ($10585 million). As described below, we have reduced our obligations due in 2003 by $17
million since September 10, 2000. We further intend to retire the 2003 ($108
million) obligation with the proceeds from the Proposed Arctic Gas Sale.
However, in the event we do not close the Proposed Arctic Gas Sale, we will be
required to review additional strategic alternatives to repay the $108 million
of 11 5/8 percent senior notes due May 2003. We intend to pursue additionalcontinue to evaluate open market
debt purchases of the obligations due in 2007 to further reduce debt. In 2001
Benton-Vinccler borrowed $12.3 million from a Venezuelan commercial bank for the
construction of a Tucupita to Uracoa oil pipeline. Benton-Vinccler has provided
the thirty day notice of its intention to repay its Bolivar denominated debt.
The full amount will be repaid on March 31, 2003. As of February 24, 2003, we
have cash reserves of approximately $75 million and do not expect the currency
conversion restriction to adversely affect our ability to meet our short-term
loan obligations.
Working Capital. Our capital resources and liquidity are affected by the timing
of our semiannual interest payments of approximately $11.2$4.0 million each May 1 and
November 1 on the 9.375 percent Senior Notes due in November 2007 and by receipt
of 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 $8
million currently) 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
32
restrictive or financial ratio covenants. We believe that similar arrangements
will be available to us in future quarters. At December 31, 2001, there2002, we had $91.9 million of cash or cash
equivalents.
Benton-Vinccler's oil and gas pipeline project loans allow the lender
to accelerate repayment if production ceases for a period greater than thirty
days. During the production shut-in which started in December 2002,
Benton-Vinccler was no
outstanding balance. In February 2002, the Venezuelan Bolivar was allowed to
float against the U.S. dollar. While the long-term impactgranted a waiver of this action is
uncertain, the short-term implication may be difficulty in purchasing U.S.
dollars with Bolivars and reducing U.S. dollar equivalent amounts of
Benton-Vinccler's short-term working capital facility. We are negotiating withprovision until February 18, 2003
for a bank to increase the Bolivar denominated short-term working capital facility to
approximately $12 million U.S. dollar equivalent. We do not expect this action
to have a material impact on Benton-Vinccler's operations.
The Proposed Arctic Gas Sale can provide the additional funds for both the
service of our debt and the development of our assets. However, in the event we
do not close the Proposed Arctic Gas Sale, we will be required to review
additional strategic alternatives to repay the $108 million of 11 5/8 percent
senior notes due May 2003. We continue 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 moreprepayment of the following
alternatives:
- restructurenext two principal obligations aggregating $0.9 million.
This prepayment, while using cash reserves, reduces our net interest expense as
the existing debt;
- managecurrent interest expense was more than the scope and timingcurrent interest income earned on
the invested funds. On February 8, 2003, Benton-Vinccler commenced production,
thereby eliminating the need for an additional waiver. A future disruption of
our capital expenditures, substantially
all of which are within our discretion;
- form joint ventures or alliances with financial or other industry
partners;
Thereproduction could trigger the debt acceleration provision again. While no
assurances can be no assurance that any of the above alternatives, or some
combination thereof, willgiven, we believe Benton-Vinccler would be available or, if available, will be on terms
acceptableable to us.obtain
another waiver.
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,
-------------------------------------------------------------------------
(IN THOUSANDS)
2002 2001 2000
1999
-------- -------- --------
(IN THOUSANDS)---------- ---------- ----------
Net cash provided by (used in) operating activities.........................................activities............ $ 42,627 $ 36,608 $ 51,763 $ (1,392)
Net cash provided by (used in) investing activities.........................................activities.. 126,492 (48,012) (28,772) 20,989
Net cash provided by (used in) financing activities.........................................activities.. (113,642) 5,296 (29,006)
(15,648)
-------- -------- ------------------ ---------- ----------
Net increase (decrease) in cash...................... $ 55,477 $ (6,108) $ (6,015)
$ 3,949
======== ======== ================== ========== ==========
30
At December 31, 2001,2002, we had current assets of $43.5$132.0 million and
current liabilities of $44.1$35.0 million, resulting in working capital of $97.0
million and a current ratio of 3.8:1. This compares with a negative working
capital of $0.6 million and a negative current ratio. This compares with our working capital of
$12.3 million and a current ratio of 1.24:1 at December 31, 2000.2001. The
decreaseincrease in working capital of $13.0$97.6 million was primarily due to lowerhigher oil
prices and additional investments in and advances tothe Arctic Gas Company during the year
ended December 31, 2001.
Geoilbent has reduced its 2002 capital budget to approximately $16.6
million, of which $2.7 million is for the North Gubkinskoye Field, $9.7 million
is for the South Tarakovskoye Field, $2.2 million is to carry out seismic and
related exploration activity and $2.0 million is for natural gas plant economic,
technical and feasibility studies. Geoilbent's 2002 operating budget includes
$16 million for principal payments on the loan facility. In addition, Geoilbent
had outstanding accounts payable of $26.6 million as of December 31, 2001,
primarily to contractors and vendors for drilling and construction services.
Although Geoilbent's reduced capital expenditure budget may help to
alleviate any shortfall of funds available to make payments to the banks and its
creditors as those payments come due, it is uncertain that Geoilbent's cash flow
from operations will be sufficient to do so, and it may be necessary for
Geoilbent to obtain capital contributions from its partners, including the
Company, to have sufficient funds to make these payments on a timely basis.
Although the Company may consider making such a capital contribution, there can
be no assurances that the Company will do so, nor can there be any assurances
that Geoilbent's other partner will be willing or able to do so. Under Russian
law, a creditor can force a company into involuntary bankruptcy if the company's
payments have been due for more than 90 days.
33
Sale.
Cash Flow from Operating Activities. During the yearyears ended December
31, 20012002 and 2000,2001, net cash provided by (used in) operating activities was approximately
$42.6 million and $36.6 million, and $51.8respectively. The $6.0 million respectively. Cash flow from
operating activities decreased by $15.2 million during the year ended December
31, 2001 compared with 2000. Thisincrease was
primarily due to collections of accruedhigher oil revenues.revenues and lower operating expenses.
Cash Flow from Investing Activities. During the year ended December
31, 20012002 and 2000,2001, we had drilling and production relatedproduction-related capital expenditures
of approximately $43.4$43.3 million and $57.2$43.4 million, respectively. Of the 20012002
expenditures, $35.7$42.5 million was attributable to the development of the South
Monagas Unit and $7.7$0.8 million was attributable to the Delta Centro Block in
Venezuela.
In addition, during the year ended December 31, 2001, we increased our
investment in Arctic Gas by $16.8 million.
We expect capital expenditures of approximately $29.1 million at the South
Monagas Unit during the next 12 months.Lakeside Exploration Prospect.
The timing and size of the investmentscapital expenditures for the South Monagas Unit
are substantiallyentirely at our discretion. We anticipate that Geoilbent will continue to
fund its expenditures through its own cash flow and credit facilities and potentially a shareholder contribution.facilities. Our
remaining capital commitments worldwide are relatively minimal and are
substantially at our discretion. We will also be required to make annual
interest payments of approximately $11.2$8.0 million related to our outstanding senior notes in April
2002 and $4.9 million in November 2002, assuming we closeon the Proposed Arctic
Gas Sale and retire $108 million of the 11 5/8 percent senior notes prior to
November 2002.2007 Notes.
We continue to assess production levels and commodity prices in
conjunction with our capital resources and liquidity requirements.
The results from the new
wells drilledBenton-Vinccler entered into a commodity contract (costless collar) in the Tucupita Field in Venezuela under the alliance agreements
with Schlumberger indicate that the reservoir formation quality is2002 and,
as expected,
but may be sensitive to drilling and completion practices.described above, a WTI crude oil "put" for a portion of 2003.
Cash Flow from Financing Activities. In May 1996, we issued $125 million
in 11 5/8 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 3/89.375 percent senior unsecured notes due November 1, 2007, of which
we subsequently repurchased $10$30 million at their par value for cash. Interest on
all of thethese 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, 2001,2002, we were in compliance with all covenants of the
indentures.indenture.
We have a deferred drilling and completion obligations under our alliance
with Schlumberger and with Flint South America, Inc as well as aan approximately $11,000 lease obligation per month for our
Houston office space. This lease is valid through August 2004. The following
table summarizes our contractual obligations at December 31, 2002.
PAYMENTS (IN THOUSANDS) DUE BY PERIOD
--------------------------------------------------------------------------------------------------------------------------------
LESS THAN AFTER 4
CONTRACTUAL OBLIGATION TOTAL 1 YEAR 1-2 YEARS 3-4 YEARS YEARS
- ---------------------- -------- --------- --------- --------- --------
(IN THOUSANDS)----------- ----------- ----------- ----------- -----------
Long Term Debt.................... $224,015Debt $ 2,432 $113,544 $2,432 $105,607
Deferred Drilling and
Completion...................... 8,871 8,871106,567 $ 1,867 $ 7,035 $ 7,035 $ 90,630
Building Lease.................... 396Lease 264 132 264
-------- ------- -------- ------ --------
Total............................. $233,282 $11,435 $113,808 $2,432 $105,607
======== ======= ======== ====== ========132 -- --
----------- ----------- ----------- ----------- -----------
Total $ 106,831 $ 1,999 $ 7,167 $ 7,035 $ 90,630
=========== =========== =========== =========== ===========
While we can give you no assurance, we currently believe that our cash
flow from operations supplemented by borrowingscoupled with our cash and asset sales if required,marketable securities on hand
will provide sufficient capital resources and liquidity 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 priceprices, the purchase of a WTI crude oil
"put" (discussed above) and production levels, and our assumptions that there
will be no further disruptions to our production and the availability of
short-term working capital facilities of up to $12 million currently during the
time periods between the submission of quarterly invoices tothat PDVSA by
Benton-Vinccler
34
and the subsequent payments of these invoices by PDVSA and other financial
alternatives.will timely pay
our invoices. Actual results could be materially affected if there is a
significant decreasechange in either priceour expectations or production levels related to the South
Monagas Unit.assumptions. 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 and political conditions that
have historically affected the oil and natural gas business. Additionally,
prices for oil are subject to fluctuations in response to changes in supply,
market uncertainty and a variety of factors beyond our control.
However, weWe currently have a significant debt obligationsobligation of $85 million payable
in May 2003
and November 2007 of $108 million and $105 million, respectively.2007. Our ability to meet our debt obligationsobligation and to reduce our
level of debt depends on the successful implementation of our strategic
objectives, in particular the timely
close of the Proposed Arctic Gas Sale. While we believe the Proposed Arctic Gas
Sale will be consummated, there can be no assurance that the transaction will
close.
In the event that the Transaction does not close, we will be required to
review additional strategic alternatives to repay the $108 million due in May
2003 in debt, including but not limited to, selling all or part of our existing
assets in Venezuela and Russia, restructuring our debt, some combination
thereof, or selling the Company. However, no assurances can be given that any of
these steps can be successfully completed or that we ultimately will determine
that any of the steps should be taken.
YEARS ENDED DECEMBERobjectives.
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.
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
35
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 13 to the Audited
Financial Statements in Item 14 -- Exhibits, Financial Statement
Schedules and Reports on Form 8-K 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.
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-
36
Vinccler are made in U.S. dollars into its United States bank account, and
Benton-Vinccler was 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, and debt obligations
and dividends.within the Russian Federation. As noted above under CAPITAL RESOURCES AND
LIQUIDITY, Venezuela imposed currency exchange restrictions on February 5, 2003.
We are unable to predict the impact of the currency controls on us or
Benton-Vinccler as the Government has not issued final regulations.
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 with 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, 2001,2002, our net foreign exchange gain
attributable to our Venezuelan operationinternational operations was $0.7$4.6 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 applicationCRITICAL ACCOUNTING POLICIES
Principles 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.
SIGNIFICANT ACCOUNTING POLICIESConsolidation
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 and Arctic Gas based on a fiscal year
ending September 30.
Oil and natural gas revenue is accrued monthly based on sales. Each
quarter, Benton-Vinccler invoices PDVSA based on barrels of oil accepted by
PDVSA during the quarter, using quarterly adjusted U.S. dollar contract service
fees per barrel.
The operating service agreement provides for Benton-Vinccler to
receive an operating fee for each barrel of crude oil delivered. It also
provides the right to receive a capital recovery fee for certain of its capital
expenditures, provided that such operating feeProperty 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.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. 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. Due to the
unpredictable nature of exploration drilling activities, the amount and timing
of impairment expenses are difficult to predict with any certainty.
37
The full cost method of accounting uses proved reserves in the
calculation of depletion, depreciation and amortization. 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.
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
32
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. Changes in previous estimates of proved reserves result from new
information obtained from production history and changes in economic factors. A
large portion of our proved reserves base from consolidated operations is
comprised of oil and gas properties that are sensitive to oil price volatility.
We are susceptible to significant upward and downward revisions to our proved
reserve volumes and values as a result of changes in year end oil and gas prices
and the corresponding adjustment to the projected economic life of such
properties. Prices for oil and gas are likely to continue to be volatile,
resulting in future revision to our proved reserve base. 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. The preparationThese rules
generally require that we price our future oil and gas production at the oil and
gas prices in effect at the end of financial statements in conformity with accounting
principles generally acceptedeach fiscal quarter and require a write-down
if our capitalized costs exceed this "ceiling," even if prices declined for only
a short period of time. We have had no write-downs due to these ceiling test
limitations since 1998. Given the volatility of oil and gas prices, it is likely
that our estimate of discounted future net revenues from proved oil and gas
reserves will change 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. The most significant estimates pertain to
provednear term. If oil plant products and gas reserve volumes andprices decline
significantly in the future, development
costs. Actual resultseven if only for a short period of time,
write-downs of our oil and gas properties could differoccur. Write-downs required by
these rules do not directly impact our cash flows from those estimates.operating activities.
Income Taxes
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 carry
forwards. 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.
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under the purchase method. For all business combinations for which
the date of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognition of intangible assets separately from
goodwill. SFAS 141 also requires unallocated negative goodwill (in a case where
the purchase price is less than fair market value of the acquired assets) to be
written off immediately as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to 40 years. In
August 2001, the FASB also approved SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of." The new accounting model for long-lived assets to be disposed
of by sale applies to all long-lived assets, including discontinued operations,
and replaces the provisions of APB Opinion No. 30, "Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business", for
the disposal of segments of a business. SFAS 144 requires that those long-lived
assets be measured at the lower of carrying amount or fair value less cost to
sell, whether reported in continuing operations or in discontinued operations.
Therefore, discontinued operations will no longer be measured at net realizable
value or include amounts for operating losses that have not yet occurred. SFAS
144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the
38
entity and that will be eliminated from the ongoing operations of the entity in
a disposal transaction. The provisions of SFAS 144 are effective for financial
statements issued for fiscal years beginning after December 15, 2001 and,
generally are to be applied prospectively. These statements are not expected to
have a material impact on our financial position, results of operations, or cash
flows.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations." SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets such as wells
and production facilities. SFAS 143 guidance covers (1) the timing of the
liability recognition, (2) initial measurement of the liability, (3) allocation
of asset retirement cost to expense, (4) subsequent measurement of the liability
and (5) financial statement disclosures. SFAS 143 requires that an asset
retirement cost should be capitalized as part of the cost of the related long-
lived asset and subsequently allocated to expense using a systematic and
rational method. The Company will adopt the statement effective no later than
January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, the Company cannot reasonably estimate the
effect of the adoption of this statement on its financial position, results of
operations or cash flows.
COST REDUCTIONS
In an effort to reduce general and administrative expenses, we closed our
Carpinteria, California office. We completed our relocation to Houston, Texas.
The technical capabilities of the field offices managing the key foreign assets
have been enhanced, particularly in Venezuela. Accountability has been
transferred our offices in Maturin, Venezuela and Western Siberia, Russia.
Venezuelan operating costs were reviewed and reduced to $4.05 per Bbl before a
non-recurring charge for fuel gas use for the period of 1997 through 2000
compared with average operating cost of $5.01 per Bbl in 2000. We expect
operating costs to average between $3.00 and $3.50 per Bbl sold in 2002.
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.
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 decreased from approximately $14.94 per Bbl for
the year ended December 31, 2000 to $12.52 per Bbl for the year ended December
31, 2001. During the same period, the average price we received for oil in
Russia increased from $18.54 per Bbl to $19.51 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;
39
- political and economic conditions in oil producing countries,
particularly those in Russia and the Middle East; and
- overall economic conditions.
New York Stock Exchange Delisting. In October 2001, we received a letter
from the New York Stock Exchange ("NYSE") notifying us that we have fallen below
the continued listing standards of the NYSE. These standards include a total
market capitalization of at least $50 million over a 30-day trading period and
stockholders' equity of at least $50 million. According to the NYSE's notice,
our total market capitalization over the 30 trading days ended October 17, 2001,
was $48.2 million, and our stockholders' equity as of September 30, 2001, was
$16.0 million. In accordance with the NYSE's rules, we submitted a plan to the
NYSE in December detailing how we expect to reestablish compliance with the
listing criteria within the next 18 months. In January 2002, the NYSE accepted
our business plan, subject to quarterly reviews of the goals and objectives
outlined in that plan. These initiatives include continued cost reductions,
production enhancements, selling all or part of our assets in Venezuela and/or
Russia, restructuring the debt or some combination of these alternatives.
Failure to achieve the financial and operational goals may result in being
subject to NYSE trading suspension at the point the initiative or goal is not
met. As a result of a delisting, an investor will find it more difficult to
dispose or obtain quotations or market value of our common stock, which may
adversely affect the marketability of our common stock. However, given the
successful execution of our strategic plan referenced above, we are optimistic
that we will be able to meet the NYSE requirements in the future and
consequently, do not expect our stock to be delisted. As of December 31, 2001,
our stockholders' equity was $67.6 million, and as of March 25, 2002 our market
capitalization was in excess of $138 million.
The Proposed Arctic Gas Sale May Not Close. While we can give you no
assurance, we currently believe that our cash flow from operations, supplemented
by borrowings and asset sales if required, will provide sufficient capital
resources and liquidity 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 $12 million currently during the time periods between the
submission of quarterly invoices to PDVSA by Benton-Vinccler and the subsequent
payments of these invoices by PDVSA and other financial alternatives. 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. Additionally, prices for
oil are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of factors beyond our control.
However, we currently have significant debt obligations payable in May 2003
and November 2007 of $108 million and $105 million, respectively. Our ability to
meet our debt obligations and to reduce our level of debt depends on the
successful implementation of our strategic objectives, in particular the timely
closing of the Proposed Arctic Gas Sale. While we believe the Proposed Arctic
Gas Sale will be consummated, there can be no assurance that the transaction
will close.
In the event that the Proposed Arctic Gas Sale does not close, we will be
required to review additional strategic alternatives to repay the $108 million
in debt, including but not limited to, selling all or part of our existing
assets in Venezuela and Russia, restructuring our debt, some combination
thereof, or selling the Company. However, no assurances can be given that any of
these steps can be successfully completed or that we ultimately will determine
that any of the steps should be taken.
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.
40
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, 2001, approximately 63 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 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. Even if the Proposed Arctic
Gas Sale is completed, we remain leveraged. As of December 31, 2001, our
long-term debt was $221.6 million. Our long-term debt represented 77 percent of
our total capitalization at December 31, 2001. If the Proposed Arctic Gas Sale
closes, our debt level will be reduced to 41 percent of our total
capitalization. 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.
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
41
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). Since 1998, we recorded no ceiling limitation
write-downs. We cannot assure you that we will not experience ceiling limitation
write-downs in the future. We perform quarterly cost center ceiling tests of our
oil and gas properties. No ceiling test write-downs were required in 2001.
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 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. The events of September 11, 2001 forced
changes to our insurance coverage. Acts of terrorism are "excluded risks from
our property insurance coverage". We cannot assure you that our insurance will
be adequate to cover losses or liabilities. We cannot predict the continued
availability of insurance at premium levels that justify its purchase.
42
Our Concentration of Assets Increases Our Exposure to Production
Declines. During 2001, 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. Venezuela is a
member of the Organization of Petroleum Exporting Countries, which has
collectively reduced crude oil exports in an attempt to increase crude oil
prices. We have been required to curtail sales to PDVSA from time to time due to
their insufficient crude oil storage capacity. We cannot be assured that our
sales to PDVSA will not be curtailed in the future in the same manner. In March
2002, the managers of PDVSA are challenging the replacement of their senior
management by the President of Venezuela. The implications of this unrest are
uncertain at this date.
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 Currency Risk. We have significant operations outside of the
United States, principally in Venezuela and Russia. Both Venezuela and Russia
have historically been considered highly inflationary economies. 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. In February 2002,
Venezuela elected to float the Bolivar, resulting in approximately a 20 percent
devaluation. Our Venezuelan receipts are denominated in U.S. dollars, while most
expenditures are in Bolivars. Management does not expect the devaluation to have
a material impact.
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. Venezuela has had labor strikes and
demonstrations in 2001 and the first quarter of 2002. The implications and
43
results of this unrest are uncertain at this time. We are dependent on cash
flows received from Benton-Vinccler to fund our U.S. expenses, including
interest expenses for the $108 million of 11 5/8 percent senior notes and the
$105 million of 9 3/8 percent senior notes. If Venezuela imposed currency
restrictions which prohibited our receipt of funds from Benton-Vinccler, our
ability to meet our interest payments would be adversely affected. Our
international operations may also be adversely affected by laws and policies of
the United States affecting foreign trade, taxation and the possibility of
having to be subject to exclusive jurisdiction of courts in connection with
legal disputes and the possible inability to subject foreign persons to the
jurisdiction of the courts in the United States. To date, our international
operations have not been materially affected by these risks.
Minority Ownership in Geoilbent. We own 34 percent in Geoilbent. We are
reviewing ways to improve the operations, but we are a minority partner and
therefore may not be able to fully influence changes in the daily operations, if
indicated by our review.
Geoilbent has reduced its 2002 capital budget to approximately $16.6
million, of which $2.7 million is for the North Gubkinskoye Field, $9.7 million
is for the South Tarakovskoye Field, $2.2 million is to carry out seismic and
related exploration activity and $2.0 million is for natural gas plant economic,
technical and feasibility studies. Geoilbent's 2002 operating budget includes
$16 million for principal payments on the loan facility. In addition, Geoilbent
had outstanding accounts payable of $26.6 million as of December 31, 2001,
primarily to contractors and vendors for drilling and construction services.
Although Geoilbent's reduced capital expenditure budget may help to
alleviate any shortfall of funds available to make payments to the banks and its
creditors as those payments come due, it is uncertain that Geoilbent's cash flow
from operations will be sufficient to do so, and it may be necessary for
Geoilbent to obtain capital contributions from its partners, including the
Company, to have sufficient funds to make these payments on a timely basis.
Although the Company may consider making such a capital contribution, there can
be no assurances that the Company will do so, nor can there be any assurances
that Geoilbent's other partner will be willing or able to do so. Under Russian
law, a creditor can force a company into involuntary bankruptcy if the company's
payments have been due for more than 90 days.
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 in 1998 and increased to $14.94 in 2000, then
back down to $12.52 in 2001. Based on our budgeted production and costs, we will
require an average realization in Venezuela of approximately $8.64 (relates to
$18 West Texas Intermediate benchmark price) per Bbl in 2002 in order to
break-even on income from consolidated companies before our equity in earnings
from affiliated companies. We have not hedged our oil production 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.
44
INTEREST RATES
Total long-term debt at December 31, 2001, consisted of $213 million of
fixed-rate senior unsecured notes maturing in 2003 ($108 million) and 2007 ($105
million) on debt. 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, 2001.
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-39.
45
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported under this item.
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", "Stock Ownership", and
"Certain Relationships and Related Transactions" in our Proxy Statement for
the 2002 Annual Meeting of Shareholders.
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, 2001 and 2000... S-2
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2000, and 1999......................... S-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2001, 2000, and 1999............. S-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000, and 1999......................... S-5
Notes to Consolidated Financial Statements.................. S-7
2. Consolidated Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
46
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 (Incorporated by reference to Exhibit 3.3 to
our Form 10-Q, filed August 13, 2001).
4.1 Form of Common Stock Certificate (Previously filed as an
exhibit to our S-1 Registration Statement (Registration No.
33-26333)).
10.1 Form of Employment Agreements (Exhibit 10.19) (Previously
filed as an exhibit to our S-1 Registration Statement
(Registration No. 33-26333)).
10.2 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)).
10.3 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)).
10.4 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)).
10.5 Operating Service Agreement between Benton Oil and Gas
Company 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)).
10.6 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).
10.7 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).
10.8 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).
10.9 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).
10.10 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).
10.11 Benton Oil and Gas Company 1999 Employee Stock Option Plan
(Incorporated by reference to Exhibit 10.21 to our Form
10-K, filed on April 2, 2001).
10.12 Benton Oil and Gas Company Non-Employee Director Stock
Purchase Plan (Incorporated by reference to Exhibit 10.21 to
our Form 10-K, filed on April 2, 2001).
10.13 Employment Agreement dated December 7, 2000 between Benton
Oil and Gas Company and Steven W. Tholen (Incorporated by
reference to Exhibit 10.21 to our Form 10-K, filed on April
2, 2001).
10.14 Note payable agreement dated March 8, 2001 between
Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a
note in the principal amount of $6,000,000 with interest at
LIBOR plus five percent, for financing of Tucupita Pipeline
(Incorporated by reference to Exhibit 10.24 to our Form
10-Q, filed on May 15, 2001).
47
10.15 Note payable agreement dated March 8, 2001 between
Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a
note in the principal amount of 4,435,200,000 Venezuelan
Bolivars (approximately $6.3 million) at a floating interest
rate, for financing of Tucupita Pipeline (Incorporated by
reference to Exhibit 10.25 to our Form 10-Q, filed on May
15, 2001).
10.16 Change of Control Severance Agreement effective May 4, 2001
(Incorporated by reference to Exhibit 10.26 to our Form
10-Q, filed on August 13, 2001).
10.17 Alexander E. Benton Settlement and Release Agreement
effective May 11, 2001 (Incorporated by reference to Exhibit
10.27 to our Form 10-Q, filed on August 13, 2001).
10.18 Michael B. Wray Termination Agreement effective May 7, 2001
(Incorporated by reference to Exhibit 10.28 to our Form
10-Q, filed on August 13, 2001).
10.19 Michael B. Wray Consulting Agreement effective May 7, 2001
(Incorporated by reference to Exhibit 10.29 to our Form
10-Q, filed on August 13, 2001).
10.20 Relocation/Reduction in Force Severance Plan effective June
5, 2001 (Incorporated by reference to Exhibit 10.30 to our
Form 10-Q, filed on August 13, 2001).
10.21 First Amendment to Change of Control Severance Plan
effective June 5, 2001 (Incorporated by reference to Exhibit
10.31 to our Form 10-Q, filed on August 13, 2001).
10.22 Amended Benton Oil and Gas Company Non-Employee Director
Stock Purchase Plan (Incorporated by reference to Exhibit
10.1 to our Form 10-Q, filed on November 31, 2001)
10.23 Employment Agreement dated December 20, 2000 between Benton
Oil and Gas Company and Robert Stephen Molina.
10.24 Employment Agreement dated November 14, 2001, between Benton
Oil and Gas Company and Kurt A. Nelson.
10.25 Sale and Purchase Agreement dated February 27, 2002 between
Benton Oil and Gas Company and Sequential Holdings Russian
Investors Limited regarding the sale of Benton Oil and Gas
Company's 68 percent interest in Arctic Gas Company.
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.
(b) Reports on Form 8-K
None.
48
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, of stockholders' equity and of
cash flows present fairly, in all material respects, the financial position of
Benton Oil and Gas Company and its subsidiaries at December 31, 2001 and 2000,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2001 in conformity with accounting
principles generally accepted in the United States of America. In addition, in
our opinion, the related financial statement schedule listed in the index
appearing under Item 14(a)(2) on page 46 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.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 28, 2002
S-1
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-------------------------
2001 2000
----------- -----------
(IN THOUSANDS, EXCEPT PER
SHARE DATA)
ASSETS
Current Assets:
Cash and cash equivalents................................. $ 9,024 $ 15,132
Restricted cash........................................... 12 12
Marketable securities..................................... -- 1,303
Accounts and notes receivable:
Accrued oil sales....................................... 23,138 38,003
Joint interest and other, net........................... 9,520 6,778
Prepaid expenses and other................................ 1,839 2,404
--------- ---------
Total Current Assets............................... 43,533 63,632
Restricted Cash............................................. 16 10,920
Other Assets................................................ 4,718 5,891
Deferred Income Taxes....................................... 57,700 4,293
Investments In and Advances To Affiliated Companies......... 100,498 77,741
Property and Equipment:
Oil and gas properties (full cost method-costs of $16,808
and $16,634 excluded from amortization in 2001 and 2000,
respectively)........................................... 533,950 490,548
Furniture and fixtures.................................... 7,399 11,049
--------- ---------
541,349 501,597
Accumulated depletion, depreciation, and amortization..... (399,663) (377,627)
--------- ---------
Total Property and Equipment....................... 141,686 123,970
--------- ---------
$ 348,151 $ 286,447
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable, trade and other......................... $ 8,132 $ 12,804
Accrued expenses.......................................... 25,840 25,797
Accrued interest payable.................................. 3,894 3,733
Income taxes payable...................................... 3,821 3,214
Short-term borrowings..................................... -- 5,714
Current portion of long-term debt......................... 2,432 --
--------- ---------
Total Current Liabilities.......................... 44,119 51,262
Long-Term Debt.............................................. 221,583 213,000
Commitments and Contingencies............................... -- --
Minority Interest........................................... 14,826 9,281
Stockholders' Equity:
Preferred stock, par value $0.01 a share; Authorized 5,000
shares; outstanding, none
Common stock, par value $0.01 a share; Authorized 80,000
shares at December 31, 2001 and 2000; issued and
outstanding 34,164 and 33,872 at December 31, 2001 and
2000.................................................... 342 339
Additional paid-in capital................................ 168,108 156,629
Accumulated deficit....................................... (100,128) (143,365)
Treasury stock, at cost, 50 shares........................ (699) (699)
--------- ---------
Total Stockholders' Equity......................... 67,623 12,904
--------- ---------
$ 348,151 $ 286,447
========= =========
See accompanying notes to consolidated financial statements.
S-2
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
---------------------------------------
2001 2000 1999
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
REVENUES
Oil and natural gas sales................................. $122,386 $140,284 $ 89,060
-------- -------- --------
EXPENSES
Operating expenses........................................ 42,759 47,430 39,393
Depletion, depreciation and amortization.................. 25,516 17,175 16,519
Write-down of oil and gas properties and impairments...... 468 1,346 25,891
General and administrative................................ 20,072 16,739 25,969
Taxes other than on income................................ 5,370 4,390 3,813
-------- -------- --------
94,185 87,080 111,585
-------- -------- --------
Income (Loss) from Operations............................... 28,201 53,204 (22,525)
Other Non-Operating Income (Expense)
Investment earnings and other............................. 3,088 8,559 8,986
Interest expense.......................................... (24,875) (28,973) (29,247)
Net gain on exchange rates................................ 768 326 1,044
-------- -------- --------
(21,019) (20,088) (19,217)
-------- -------- --------
Income (Loss) from Consolidated Companies Before Income
Taxes and Minority Interests.............................. 7,182 33,116 (41,742)
Income Tax Expense (Benefit)................................ (35,698) 14,032 (7,526)
-------- -------- --------
Income (Loss) Before Minority Interests..................... 42,880 19,084 (34,216)
Minority Interests in Consolidated Subsidiary Companies..... 5,545 7,869 937
-------- -------- --------
Income (Loss) from Consolidated Companies................... 37,335 11,215 (35,153)
Equity in Net Earnings of Affiliated Companies.............. 5,902 5,313 2,869
-------- -------- --------
Income (Loss) Before Extraordinary Income................... 43,237 16,528 (32,284)
Extraordinary Income on Debt Repurchase, Net of Tax of $0... -- 3,960 --
-------- -------- --------
Net Income (Loss)........................................... $ 43,237 $ 20,488 $(32,284)
======== ======== ========
Net Income (Loss) Per Common Share:
Basic:
Income (Loss) before extraordinary income................. $ 1.27 $ 0.54 $ (1.09)
Extraordinary Income...................................... -- 0.13 --
-------- -------- --------
Net Income (Loss)......................................... $ 1.27 $ 0.67 $ (1.09)
======== ======== ========
Diluted:
Income (Loss) Before Extraordinary Income................. $ 1.27 $ 0.53 $ (1.09)
Extraordinary Income...................................... -- 0.13 --
-------- -------- --------
Net Income (Loss)......................................... $ 1.27 $ 0.66 $ (1.09)
======== ======== ========
See accompanying notes to consolidated financial statements.
S-3
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
EMPLOYEE
COMMON ADDITIONAL NOTE
SHARES COMMON PAID-IN ACCUMULATED TREASURY RECEIVABLE,
ISSUED STOCK CAPITAL DEFICIT STOCK NET TOTAL
------ ------ ---------- ----------- -------- ----------- --------
(IN THOUSANDS)
BALANCE AT JANUARY 1,
1999..................... 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
Issuance of common shares:
Non-employee director
compensation.......... 292 3 471 -- -- -- 474
Tax benefits related to
stock option
compensation.......... -- -- 11,008 -- -- -- 11,008
Net Income................. -- -- -- 43,237 -- -- 43,237
------ ---- -------- --------- ----- ------- --------
BALANCE AT DECEMBER 31,
2001..................... 34,164 $342 $168,108 $(100,128) $(699) $ -- $ 67,623
====== ==== ======== ========= ===== ======= ========
See accompanying notes to consolidated financial statements.
S-4
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------
(IN THOUSANDS)
Cash Flows From Operating Activities:
Net income (loss)......................................... $ 43,237 $ 20,488 $(32,284)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation and amortization............... 25,516 17,175 16,519
Write-down and impairment of oil and gas properties.... 468 1,346 25,891
Amortization of financing costs........................ 1,179 1,375 1,396
(Gain) loss on disposition of assets................... (336) 60 44
Equity in earnings of affiliated companies............. (5,902) (5,313) (2,869)
Allowance and write-off of employee notes and accounts
receivable........................................... 365 331 6,231
Non-cash compensation related charges.................. 474 -- --
Minority interest in undistributed earnings of
subsidiaries......................................... 5,545 7,869 937
Extraordinary income from repurchase of debt........... -- (3,960) --
Tax benefits related to stock option compensation...... 11,008 -- --
Deferred income taxes.................................. (53,407) 7,893 (9,210)
Changes in operating assets and liabilities:
Accounts and notes receivable.......................... 11,756 (12,780) (6,414)
Prepaid expenses and other............................. 565 (769) 1,750
Accounts payable....................................... (4,671) 9,487 (3,142)
Accrued interest payable............................... 161 (953) (711)
Accrued expenses....................................... 43 7,971 (166)
Income taxes payable................................... 607 1,543 636
-------- -------- --------
Net Cash Provided by (Used In) Operating Activities.... 36,608 51,763 (1,392)
-------- -------- --------
Cash Flows from Investing Activities:
Proceeds from sale of property and equipment.............. -- 800 15,100
Additions of property and equipment....................... (43,364) (57,196) (36,984)
Investment in and advances to affiliated companies........ (16,855) (11,071) (13,052)
Increase in restricted cash............................... (57) (271) (214)
Decrease in restricted cash............................... 10,961 35,800 19,435
Purchases of marketable securities........................ (15,067) (12,638) (29,173)
Maturities of marketable securities....................... 16,370 15,804 65,877
-------- -------- --------
Net Cash Provided by (Used In) Investing Activities.... (48,012) (28,772) 20,989
-------- -------- --------
Cash Flows from Financing Activities:
Net proceeds from exercise of stock options and extension
of warrants............................................ -- 330 24
Proceeds from issuance of short term borrowings and notes
payable................................................ 21,112 15,087 --
Payments on short term borrowings and notes payable....... (15,746) (47,488) (15,439)
(Increase) decrease in other assets....................... (70) 3,065 (233)
-------- -------- --------
Net Cash Provided by (Used In) Financing Activities.... 5,296 (29,006) (15,648)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents... (6,108) (6,015) 3,949
Cash and Cash Equivalents at Beginning of Year.............. 15,132 21,147 17,198
-------- -------- --------
Cash and Cash Equivalents at End of Year.................... $ 9,024 $ 15,132 $ 21,147
======== ======== ========
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense............ $ 25,721 $ 28,326 $ 30,346
======== ======== ========
Cash paid during the year for income taxes................ $ 3,057 $ 2,950 $ 2,600
======== ======== ========
See accompanying notes to consolidated financial statements.
S-5
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 13).
See accompanying notes to consolidated financial statements.
S-6
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
PRINCIPLES OF CONSOLIDATION
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"), based on a fiscal year ending September 30 (see Note 2).
REVENUE RECOGNITION
Oil revenue is accrued monthly based on production and delivery. Each
quarter, Benton-Vinccler invoices Petroleos de Venezuela, S.A. ("PDVSA") or
affiliates based on barrels of oil accepted by PDVSA during the quarter, using
quarterly adjusted U.S. dollar contract service fees per barrel. The operating
service agreement provides for Benton-Vinccler to receive an operating fee for
each barrel of crude oil delivered. It also provides 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.
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 at December 31, 2000.
ACCOUNTS AND NOTES RECEIVABLE
Allowance for doubtful accounts related to employee notes at December 31,
2001 and 2000 was $6.5 million and $6.2 million, respectively (see Note 13).
Allowance for doubtful accounts related to joint interest and other accounts
receivable was $0.3 million at December 31, 2000.
S-7
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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 $0.6
million, $1.5 million and $2.1 million for the years ended December 31, 2001,
2000 and 1999, respectively, and capitalized interest of $0.9 million and $0.6
million for the years ended December 31, 2001 and 2000, respectively. Only
overhead that is directly identified with acquisition, exploration or
development activities is capitalized. All costs related to production, general
corporate overhead and similar activities are expensed as incurred.
The costs of unproved properties are excluded from amortization until the
properties are evaluated. 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 2001, 2000
and 1999, the Company recognized $0.5 million, $1.3 million and $25.9 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, 2001 consisted of the following by year
incurred (in thousands):
PRIOR TO
TOTAL 2001 2000 1999 1999
------- ---- ---- ---- --------
Property acquisition costs..................... $15,106 $ -- $ -- $-- $15,106
Exploration costs.............................. 1,702 174 518 46 964
------- ---- ---- --- -------
$16,808 $174 $518 $46 $16,070
======= ==== ==== === =======
Substantially all of the excluded costs at December 31, 2001 relate to the
acquisition of Benton Offshore China Company and exploration related to its Wan
"An Bei property. The remaining excluded costs of $0.6 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,
2001, 2000 and 1999 was $22.1 million, $15.3 million and $14.8 million ($2.26,
$1.68 and $1.53 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 $3.4 million, $1.8
million and $1.6 million for the years ended December 31, 2001, 2000 and 1999,
respectively.
S-8
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The major components of property and equipment at December 31 are as
follows (in thousands):
2001 2000
--------- ---------
Proved property costs....................................... $ 501,923 $ 458,571
Costs excluded from amortization............................ 16,808 16,634
Oilfield inventories........................................ 15,219 15,343
Furniture and fixtures...................................... 7,399 11,049
--------- ---------
541,349 501,597
Accumulated depletion, impairment and depreciation.......... (399,663) (377,627)
--------- ---------
$ 141,686 $ 123,970
========= =========
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. No ceiling test write-downs were required.
INCOME TAXES
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. In
the fourth quarter of 2001, a substantial portion of the valuation allowance was
reversed based on the likelihood of utilization of net operating losses in 2002.
See Note 16 to the Audited Financial Statements in Item 14 -- Exhibits,
Financial Statement Schedules and Reports on Form 8-K.
FOREIGN CURRENCY
We have significant operations outside of the United States,
principally in Venezuela and an equity investment in Russia. These countriesAmounts denominated
in non-U.S. currencies 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 that 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 and cash equivalents, marketable securities and
accounts receivable. Cash and cash equivalents are placed with commercial banks
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 inNew Accounting Pronouncements
In September 2001, the oil and natural gas business. PDVSA
purchases 100 percent of our Venezuelan oil production. Although the Company
does not currently foresee a credit risk associated with these receivables,
collection is dependent upon the financial stability of PDVSA.
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, 2001 and 2000, was approximately $138.1 million and
$137.0 million, respectively.
S-9
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
COMPREHENSIVE INCOMEFinancial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 130 ("143, Accounting for Asset
Retirement Obligations (SFAS No. 143). SFAS 130")No. 143 requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of
the related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method. SFAS No. 143 is
effective for fiscal years beginning after September 15, 2002. We will adopt
SFAS No. 143 effective January 1, 2003, and such adoption will not materially
impact the financial statements since our PDVSA operating service agreement
provides that all itemswells revert to PDVSA at contract expiration and intervening
abandonment obligations are minor. Further we believe the adoption of SFAS No.
143 by Geoilbent will not materially impact our equity in earnings given that
the fair value of such obligations 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, 2001 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.
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,material as of December 31, 1998, losses attributable toSeptember 30, 2002.
In May 2002, the minority shareholderFASB issued SFAS No. 145, Rescission of Benton-
Vinccler, our 80 percent owned subsidiary, exceeded its interest in equity
capital creating an equity deficitFASB
Statements No. 4, 44, and 64, Amendment 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.
NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting StandardsFASB Statement No. 141 "Business Combinations"
("SFAS 141")13, and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142")Technical
Corrections". SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under145 rescinds the purchase method. For all business combinations for which
the dateautomatic treatment of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognitiongains or losses from
extinguishment of intangible assets separately from
goodwill. SFAS 141 also requires unallocated negative goodwill (in a case where
the purchase price is less than fair market value of the acquired assets) to be
written off immediatelydebt as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to 40 years. In
August 2001, the FASB also approved SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of." The new accounting model for long-lived assets to be disposed
of by sale applies to all long-lived assets, including discontinued operations,
and replaces the provisions ofitems as outlined in APB Opinion No. 30,
"Reporting the Results of Operations-ReportingOperations, Reporting the Effects of Disposal of a
Segment of a Business",Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions". As allowed under the provisions of SFAS 145, we had
33
decided to adopt SFAS 145 early. Accordingly, all gains on early extinguishment
of debt have been reclassified to other non-operating income in the accompanying
consolidated financial statements.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities". The standard requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the disposal of segmentsdate of a business.commitment to an exit or disposal plan.
Examples of costs covered by the standard include lease termination costs and
certain employee severance costs that are associated with a restructuring,
discontinued operation, plant closing, or other exit or disposal activity. SFAS
144 requires that those long-lived
assets be measured at the lower of carrying amount or fair value less cost146 replaces Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to sell, whether reported in continuing operations or in discontinued operations.
Therefore, discontinued operations will no longer be measured at net realizable
value or include amounts for operating losses that have not yet occurred. SFAS
144 also broadens the reporting of discontinued operations to include all
components ofExit an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entityActivity
(including Certain Costs Incurred in a disposal transaction.Restructuring)". The provisions of this
statement shall be effective for exit or disposal activities initiated after
December 31, 2002. The Company will account for exit or disposal activities
initiated after December 31, 2002, in accordance with the provisions of SFAS 144No.
146.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure an amendment of FASB
Statement No. 123". The standard amends SFAS Statement No. 123 that provides
alternative methods of transition for an entity that voluntarily changes to the
fair value based method of accounting for stock-based employee compensation. In
addition, this statement amends the disclosure requirements of SFAS No. 123 to
require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The Company intends to adopt the
"Prospective method" which will apply the recognition provisions to all employee
awards granted, modified, or settled in 2003.
The weighted average fair value of the stock options granted from our
stock option plans during 2002, 2001 and 2000 was $4.84, $1.33 and $1.65,
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:
2002 2001 2000
----------- ----------- -----------
Expected life................................... 10.0 years 10.0 years 9.1 years
Risk-free interest rate......................... 5.0% 5.1% 6.1%
Volatility...................................... 74% 72% 74%
Dividend Yield.................................. 0% 0% 0%
We accounted 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 2002, 2001 and 2000 would have been as follows
(in thousands, except per share data):
2002 2001 2000
--------- --------- ---------
Net income as reported................................. $ 100,362 $ 43,237 $ 20,488
Add: Stock-based employee compensation expense
included in reported net income due to acceleration
of vesting of former employees......................... 915 35 110
Deduct: Total stock-based employee compensation
expense determined under fair value based method for
all grants awarded since January 1, 1995............... (2,905) (2,459) (4,374)
--------- --------- ---------
Net income ............................................ $ 98,372 $ 40,813 $ 16,224
========= ========= =========
Net income per common share:
Basic............................................... $ 2.87 $ 1.20 $ 0.53
========= ========= =========
Diluted............................................. $ 2.75 $ 1.20 $ 0.53
========= ========= =========
In November 2002 FASB interpretation, or FIN 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantee of Indebtedness of Others" was issued. FIN 45 requires that upon
34
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions for
initial recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's initial
application may not be revised or restated to reflect the effect of the
recognition and measurement provisions of FIN 45. The disclosure requirements
are effective for financial statements issued for fiscal years beginningof both interim and annual periods that
end after December 15, 2001
and, generally are2002. As of December 31, 2002, the Company does not have
any guarantor obligations.
In January 2003 FASB Interpretation 46, or FIN 46, "Consolidation of
Variable Interest Entities" was issued. FIN 46 identifies certain off-balance
sheet arrangements that meet the definition of a variable interest entity (VIE).
The primary beneficiary of a VIE is the party that is exposed to be applied prospectively. These statements are not
expected to have a material impact on our financial position, results of
operations, or cash flows.
S-10
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations." SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets such as wells
and production facilities. SFAS 143 guidance covers (1) the timingmajority of
the liability recognition, (2) initial measurementrisks and/or returns of the liability, (3) allocationVIE. In future accounting periods, the primary
beneficiary will be required to consolidate the VIE. In addition, more extensive
disclosure requirements apply to the primary beneficiary, as well as other
significant investors. We do not believe we participate in any arrangement that
would be subject to the provisions of asset retirement cost to expense, (4) subsequent measurementFIN 46.
In November 2002, the International Practices Task Force concluded that
Russia has ceased being a highly inflationary economy as of January 1, 2003. As
a result of the liabilityTask Force conclusion, companies reporting under US GAAP in
Russia will be required to apply the guidance contained in Emerging Issues Task
Force ("EITF") No. 92-4 and (5) financial statement disclosures. SFAS 143 requires that an asset
retirement cost should be capitalizedEITF No. 92-8 as part of the cost of the related
long-lived asset and subsequently allocated to expense using a systematic and
rational method. The Company will adopt the statement effective no later than January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, the Company cannot reasonably estimate2003. We have not yet
estimated the effect of the adoption of this statementthat EITF No. 92-4 and EITF No. 92-8 will have on its financial position, results of
operationsGeoilbent
or cash flows.
USE OF ESTIMATES
The preparation of financial statementsour equity position.
35
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk from adverse changes 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. The most significant estimates pertain to
proved oil, plant products and gas reserve volumes and the future development
costs. Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain items in 1999 and 2000 have been reclassified to conform to the
2001 financial statement presentation.
NOTE 2 -- INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES
Investments in Geoilbent and Arctic Gas are accounted for using the equity
method due to the significant influence we exercise over their operations and
management. Investments include amounts paid to the investee companies for
shares of stock 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 Geoilbentprices, interest rates, foreign exchange and Arctic Gas are based on a fiscal year ending
September 30.
Equity inpolitical risk, as discussed
below.
OIL PRICES
As an independent oil producer, our revenue, other income and equity
earnings and lossesprofitability, reserve values, access to capital and investments in and advances to companies
accounted for usingfuture rate of
growth are substantially dependent upon the equity method are as follows (in thousands):
GEOILBENT, LTD. ARCTIC GAS COMPANY TOTAL
----------------- ------------------- ------------------
2001 2000 2001 2000 2001 2000
------- ------- -------- -------- -------- -------
Investments:
In equity in net assets........... $28,056 $28,056 $(1,814) $(2,218) $ 26,242 $25,838
Other costs, net of
amortization................... (99) (202) 28,579 19,058 28,480 18,856
------- ------- ------- ------- -------- -------
Total investments................. 27,957 27,854 26,765 16,840 54,722 44,694
Advances............................ -- -- 28,829 21,986 28,829 21,986
Equity in earnings (losses)......... 19,307 12,310 (2,360) (1,249) 16,947 11,061
------- ------- ------- ------- -------- -------
Total.......................... $47,264 $40,164 $53,234 $37,577 $100,498 $77,741
======= ======= ======= ======= ======== =======
S-11
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- LONG-TERM DEBT AND LIQUIDITY
LONG-TERM DEBT
Long-term debt consistsprevailing prices of the following (in thousands):
DECEMBER 31, DECEMBER 31,
2001 2000
----------------- -----------------
Senior unsecured notes with interest at 9.375%
See description below..................................... $105,000 $105,000
Senior unsecured notes with interest at 11.625%
See description below..................................... 108,000 108,000
Note payable with interest at 8.7%
See description below..................................... 5,100 --
Note payable with interest at 39%
See description below..................................... 5,235 --
Non-interest bearing liability with a face value of $744
discounted at 7%. See description below................... 680 --
-------- --------
224,015 213,000
Less current portion........................................ 2,432 --
-------- --------
$221,583 $213,000
======== ========
In November 1997, we issued $115 million in 9.375 percent senior unsecured
notes due November 1, 2007 ("2007 Notes"), of which we subsequently repurchased
$10 million at their par value. In May 1996, we issued $125 million in 11.625
percent senior unsecured notes due May 1, 2003 ("2003 Notes"), of which we
repurchased $17 million at their discounted value in September 2000 and November
2000 with the issuance of 4.2 million common shares with a market value of $9.3
million and cash of $3.5 million plus accrued interest. Interest on the notes is
due May 1 and November 1 of each year. The indenture agreements provide for
certain limitations on liens, additional indebtedness, certain investments and
capital expenditures, dividends, mergers and sales of assets. In August 2001, we
received the requisite consents from the holders of the 2003 Notes and 2007
Notes to amend the indentures governing the notes, and the supplemental
indentures have become operative. The amendments enable Arctic Gas Company to
incur non-recourse debt of up to $77 million to fund itscrude oil and
gas development
program and remove stock restrictions. For all of 2001, and at December 31,
2001, we were in compliance with all covenants of the indentures.
In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan
commercial bank, in the form of two loans,natural gas. Prevailing prices for construction of a 31-mile oil
pipeline that will connect the Tucupita Field production facility with the
Uracoa central processing unit. The first loan, with an original principal
amount of $6 million, bears interest payable monthly based on 90-day LIBOR (3.7
Percent at December 31, 2001) plus 5 percent with principal payable quarterly
for five years. The second loan, in the amount of 4.4 billion Venezuelan
Bolivars (approximately $6.3 million), bears interest payable monthly based on a
mutually agreed interest rate determined quarterly or a six-bank average
published by the central bank of Venezuela. The interest rate for the quarter
ending December 2001 was 39 percent with an effective interest rate of 31
percent taking into account exchange rate gains resulting from devaluation of
the Bolivar during the quarter. In February 2002, the Bolivar was allowed to
float against the U.S. dollar. Principal on the second loan is payable quarterly
for five years beginning in September 2001. The loans provide for certain
limitations on dividends, mergers and sale of assets. At December 31, 2001, we
were in compliance with all covenants of the loans.
In 2001, a dispute arose over collection by municipal taxing regimes on the
South Monagas Unit resulting in overpayments and underpayments to adjacent
municipalities. As settlement, a portion of future municipal
S-12
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tax payments will be offset by the municipal tax that was originally overpaid.
The present value of the long-term portion of the settlement liability is $0.7
million at December 31, 2001.
The principal payment requirements for our long-term debt outstanding at
December 31, 2001 are as follows (in thousands):
2002........................................................ $ 2,432
2003........................................................ 111,112
2004........................................................ 2,432
2005........................................................ 2,432
2006........................................................ 607
Subsequent Years............................................ 105,000
--------
$224,015
========
LIQUIDITY
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.
While we can give you no assurance, we currently believe that our cash flow
from operations, if supplemented by borrowings if required, will provide
sufficient capital resources and liquidity 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 $12 million currently during the
time periods between the submission of quarterly invoices to PDVSA by
Benton-Vinccler and the subsequent payments of these invoices by PDVSA and other
financial alternatives. 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 flowssuch commodities 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. Additionally, prices for oil are subject to fluctuationswide
fluctuation in response to relatively minor changes in supply market uncertaintyand demand and a
variety of additional factors beyond our control. We currentlyHistorically, prices received
for oil production have significant debt obligations payable in Maybeen volatile and unpredictable, and such volatility is
expected to continue. Through February 14, 2003, and
November 2007we utilized a costless collar
hedge transaction with respect to a portion of $108 million and $105 million, respectively. Our abilityour oil production to meetachieve a
more predictable cash flow, establish an acceptable rate of return on our
debt obligations andTucupita drilling program, as well as to reduce our levelexposure to price
fluctuations. Benton-Vinccler has hedged a portion of debt depends onits 2003 oil production by
purchasing a WTI crude oil "put" to protect its 2003 cash flow. Because gains or
losses associated with hedging transactions are included in oil sales when the
successful implementationhedged production is delivered, such gains and losses are generally offset by
similar changes in the realized prices of the commodities. See Note 1 -
Derivatives and Hedging for a complete discussion of our strategic objectives,derivative activity.
INTEREST RATES
Total long-term debt at December 31, 2002 of $104.7 million consisted
of fixed-rate senior unsecured notes maturing in particular2007 ($85.0 million).
Benton-Vinccler has $18.2 million U.S. Dollar denominated and 1.5 million
Bolivar denominated variable rate loans. A hypothetical 10 percent adverse
change in the timely
saleinterest rate would not have had a material affect on our results
of operations.
FOREIGN EXCHANGE
For the Venezuelan operations, oil and gas 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 Geoilbent, a majority of the oil sales are
received in Rubles; 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 interestfinancial results are subject
to favorable or unfavorable fluctuations in Arctic Gas. While we believe the Proposed Arctic Gas
Sale will be consummated, there can be no assurance that the transaction will
close.
In the event that the Transaction does not close, we will be required to
review additional strategic alternatives to repay the $108 million dueexchange rates and inflation in
May
2003 in debt, including but not limited to, selling all or partthese countries. Venezuela has recently imposed currency exchange controls (see
CAPITAL RESOURCES AND LIQUIDITY above).
POLITICAL RISK
The stability of our existing
assetsgovernment in Venezuela and Russia, restructuring our debt, some combination
thereof, or selling the Company. However, no assurances can be given that any of
these steps can be successfully completed or that we ultimately will determine
that any of the steps should be taken.
We,government's
relationship with the advicestate-owned national oil company, PDVSA, remain
significant risks for our company. PDVSA is the sole purchaser of all Venezuelan
oil and gas production. In April 2002 there was a failed attempt to remove the
President of Venezuela. During this period, sales were curtailed but our financial and legal advisers and after having
conducted a comprehensive review to consider our strategic alternatives,
initiated a process in May 2001 intended to effectively extendoil
production was not interrupted, but it did delay the maturityimportation of the senior notes due May 1, 2003 by exchanging new 13.125 percent senior notes
due December 2007 plus warrants to purchase shares of our common stock for each
of the 2003 Notes. While we believe the
S-13
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
terms of the exchange offer madecritical
equipment, which contributed to the holdersslowdown in our drilling operations. From
December 14, 2002 through February 6, 2003, no sales were made because of
PDVSA's inability to accept our oil due to the 2003 Notes were in the
best interest of the noteholders and our shareholders, the majority of the
noteholders would not exchange their notes for notes of a longer maturity on
economic terms which were acceptable to us.national civil work stoppage. As
a result, 2002 sales were reduced by approximately 550,000 barrels and sales in
2003 were reduced by an estimated 1.2 million barrels. While the exchange offer was
withdrawn in July 2001. In August 2001, we solicitedsituation has
stabilized and received the requisite
consents from the holdersproduction is returning to normal, there continues to be
political and economic uncertainty that could lead to another disruption of both the 2003 Notes and the 2007 Notes to amend
certain covenants in the indentures governing the notes to enable Arctic Gas to
incur nonrecourse debt of up to $77 million to fund its oil and gas development
program and remove stock restrictions. As an incentive to consent, we offered to
pay each noteholder an amount in cash equal to $2.50 per $1,000 principal amount
of notes held for which executed consents were received. The total amount of
consent fees paid to the consenting noteholders was $0.3 million, which has been
included in general and administrative expenses.
Additionally, we implemented a plan designed to lower operating costs,
reduce general and administrative costs at our
corporate headquarters and to
transfer geological and geophysical activities to our overseas offices in
Maturin, Venezuela and in Western Siberia and Moscow, Russia.
On February 27, 2002, we signed a Sale and Purchase Agreement to sell our
68 percent interest in Arctic Gas Company to a nominee of the Yukos Oil Company
for $190 million plus approximately $30 million as repayment of intercompany
loans owed to us by Arctic Gas. If this transaction closes, it will alleviate
our short-term liquidity issue. However, in the event the transaction does not
close, we will be required to review additional strategic alternatives to repay
the $108 million of 11 5/8 percent senior notes due May 2003.
NOTE 4 -- COMMITMENTS AND CONTINGENCIES
On February 17, 1998, the WRT Creditors Liquidation Trust ("WRT Trust")
filed suit in the United States Bankruptcy Court, Western District of Louisiana
against us and Benton Oil and Gas Company of Louisiana, a.k.a. Ventures Oil &
Gas of Louisiana ("BOGLA"), seeking a determination that the sale by BOGLA to
Tesla Resources Corporation ("Tesla"), a wholly owned subsidiary of WRT Energy
Corporation, of certain West Cote Blanche Bay properties for $15.1 million,
constituted a fraudulent conveyance under 11 U.S.C. Sections 544, 548 and 550
(the "Bankruptcy Code"). The alleged basis of the claim is that Tesla was
insolvent at the time of its acquisition of the properties, and that it paid a
price in excess of the fair value of the property. A trial commenced on May 1,
2000 that concluded at the end of August 2000, and post trial briefs were filed.
The WRT Trust has filed a Notice of Appeal with the Bankruptcy Court; however,
we believe that the appeal will result in an outcome consistent with the court's
prior decision.
In May 1996, we entered into an agreement with Morgan Guaranty that
provided for an $18 million cash collateralized five-year letter of credit to
secure our performance of the minimum exploration work program required on the
Delta Centro Block in Venezuela.sales. As a result of expenditures made related to the explorationnational civil work program,stoppage, the letterGovernment of
credit had been reduced to $7.7 million
asVenezuela terminated several thousand PDVSA employees and announced a
decentralization of December 31, 2000. In January 2001, we and our bidding partners reached an
agreement to terminatePDVSA's operations. While the remainder of the exploration work program in exchange
for the unused portion of the standby letter of credit of $7.7 million.
We have employment contracts with four executive officers 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 November 11, 2002 to July 9, 2003.
In July 2001, we leased for three years office space in Houston, Texas for
approximately $11,000 per month. We lease 17,500 square feet of space in a
California building that we no longer occupy under a lease agreement that
expires in December 2004, all of which has been subleased for rents that
approximate our lease costs.
In October 2001, we received a letter from the New York Stock Exchange
("NYSE") notifying us that we have fallen below the continued listing standards
of the NYSE. These standards include a total market
S-14
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
capitalization of at least $50 million over a 30-day trading period and
stockholders' equity of at least $50 million. According to the NYSE's notice,
our total market capitalization over the 30 trading days ended October 17, 2001,
was $48.2 million, and our stockholders' equity as of September 30, 2001, was
$16.0 million. In accordance with the NYSE's rules, we submitted a plan to the
NYSE in December detailing how we expect to reestablish compliance with the
listing criteria within the next 18 months. In January 2002, the NYSE accepted
our business plan, subject to quarterly reviews of the goals and objectives
outlined in that plan. These initiatives include continued cost reductions,
production enhancements, selling all or part of our assets in Venezuela and/or
Russia, restructuring the debt or some combinationeffect of these alternatives.
Failurechanges cannot
be predicted, it could adversely affect PDVSA's ability to achieve the financialmanage its contracts
and operational goals may result in being
subject to NYSE trading suspension at the point the initiative or goal is not
met.meet its obligations with its suppliers and vendors, such as
Benton-Vinccler. As a result of a delisting, an investor will find it more difficultthe situation in PDVSA, its payment to
dispose or obtain quotations or market value of our common stock, which may
adversely affect the marketability of our common stock. However, given our
strategic plan referenced above, we are optimistic that we will be able to meet
the NYSE requirementsBenton-Vinccler for crude delivered in the future and, consequently, do not expect our stock
to be delisted.
Geoilbent has reduced itsfourth quarter 2002 capital budget to approximately $16.6
million, of which $2.7 million is for the North Gubkinskoye Field, $9.7 million
is for the South Tarakovskoye Field, $2.2 million is to carry out seismic and
related exploration activity and $2.0 million is for natural gas plant economic,
technical and feasibility studies. Geoilbent's 2002 operating budget includes
$16 million for principal payments on the loan facility. In addition, Geoilbent
had outstanding accounts payable of $26.6 million as of December 31, 2001,
primarily to contractors and vendors for drilling and construction services.
Although Geoilbent's reduced capital expenditure budget may help to
alleviate any shortfall of funds available to make payments to the banks and its
creditors as those payments come due, it is uncertain that Geoilbent's cash flow
from operations will be sufficient to do so, and it may be necessary for
Geoilbent to obtain capital contributions from its partners, including the
Company, to have sufficient funds to make these payments on a timely basis.
Although the Company may consider making such a capital contribution, there can
be no assuranceswas late by seven
days. We believe that the Company will do so, nor can there be any assurances
that Geoilbent's other partner will be willingpayment demonstrates PDVSA's commitment to building
its production levels back to full capacity and returning to more normalized
business relations with its customers and suppliers. While we have substantial
cash reserves to withstand a future disruption, a prolonged loss of sales or ablea
failure or delay by PDVSA to do so. Under Russian
law, a creditor can force a company into involuntary bankruptcy if the company's
payments have been due for more than 90 days.
In the normal course ofpay 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 toinvoices could have a material adverse
effect on our financial position,
results of operations or liquidity.
NOTE 5 -- TAXES
TAXES OTHER THANcondition.
36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is included herein on pages S-1 through
S-37.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON INCOME
Benton-Vinccler pays a municipal tax on operating fee revenues it receives
for production from the South Monagas Unit. The components of taxes other than
on income were (in thousands):ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
37
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*
2001 2000 1999
------ ------ ------Number of securities
Number of remaining
securities to be available for
issued upon future issuance
exercise of Weighted-average under equity
outstanding exercise price compensation
options, of outstanding plans (excluding
warrants and options, warrants securities reflected
rights and rights in column (a)
Plan Category (a) (b) (c)
------------------ --------------- ---------------- --------------------
Venezuelan municipal taxes................................. $4,447 $3,164 $2,303
Severance and production taxes............................. -- 28 --
Franchise taxes............................................ 121 131 139
Payroll and other taxes.................................... 802 1,067 1,371
------ ------ ------
$5,370 $4,390 $3,813
====== ====== ======Equity compensation plans approved by
security holders 4,244,463 $8.68 310,000
Equity compensation plans not approved by
security holders(1) 1,170,650 2.92
----------- ---------- -----------
Total 5,415,113 $7.43 310,000
=========== ========== ===========
S-15
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
TAXES ON INCOME
The tax effects of significant items comprising our net deferred income
taxes as of December 31, 2001 and 2000 are as follows (in thousands):
2001 2000
-------- --------
Deferred tax assets:
Operating loss carryforwards.............................. $ 49,000 $ 37,142
Difference in basis of property........................... 19,300 4,948
Other..................................................... 9,100 16,410
Valuation allowance....................................... (19,700) (54,207)
-------- --------
Net deferred tax asset...................................... $ 57,700 $ 4,293
======== ========
The valuation allowance decreased by $37.0 million as a result of the
increase in the U.S. deferred tax assets related to the net operating loss
carryforward. Realization of deferred tax assets associated with net operating
loss carryforwards is dependent upon generating sufficient taxable income prior
to their expiration. Management believes it is more likely than not that they
will be realized through future taxable income and in particular the Proposed
Arctic Gas Sale.(1) See Note 166 of Notes to the AuditedConsolidated Financial Statements in Item 14 --
Exhibits, Financial Statement Schedules and Reports on Form 8-K.
The componentsfor a
description of income before income taxes, minority interest and
extraordinary items are as follows (in thousands):
2001 2000 1999
-------- -------- --------
Income (loss) before income taxes United States...... $(26,572) $(13,034) $(38,637)
Foreign.............................................. 33,754 46,150 (3,105)
-------- -------- --------
Total...................................... $ 7,182 $ 33,116 $(41,742)
======== ======== ========
The provision (benefit) for income taxes consisted of the following at
December 31, (in thousands):
2001 2000 1999
-------- ------- -------
Current:
United States.......................................... $ 1 $ 215 $(2,216)
Foreign................................................ 6,700 5,925 3,900
-------- ------- -------
$ 6,701 $ 6,140 $ 1,684
======== ======= =======
Deferred:
United States.......................................... $(42,405) $ -- $ --
Foreign................................................ 6 7,892 (9,210)
-------- ------- -------
(42,399) 7,892 (9,210)
-------- ------- -------
$(35,698) $14,032 $(7,526)
======== ======= =======
S-16
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A comparison of the income tax expense (benefit) at the federal statutory
rateoptions issued to our provision for income taxes is as follows (in thousands):
2001 2000 1999
-------- ------- --------
Computed tax expense at the statutory rate............ $ 4,580 $13,451 $(13,606)
State income taxes, net of federal effect............. -- (343) (307)
Effect of foreign source income and rate differentials
on foreign income................................... 1,675 (1,826) 4,507
Change in valuation allowance......................... (53,413) 2,294 5,951
Prior year adjustments................................ 2,304 1,637 (847)
Effect of tax law changes............................. -- -- (2,220)
Reclass paid-in capital............................... 11,007 -- --
All other............................................. 215 679 --
-------- ------- --------
Sub-total income tax expense (benefit)................ (33,632) 15,892 (6,522)
Effects of recording equity income of certain
affiliated Companies on an after-tax basis.......... (2,066) (1,860) (1,004)
-------- ------- --------
Total income tax expense (benefit).................... $(35,698) $14,032 $ (7,526)
======== ======= ========
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, 2001, we had, for federal income tax purposes, operating
loss carryforwards of approximately $136 million, expiring in the years 2003
through 2021.
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,individuals other than officers,
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 were granted with exercise
prices not less than the fair market value of the common stock on the date of
the grant, subject to the dollar limitations imposed by the Internal Revenue
Code. 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 discontinued future grants under the 1991-1992 Stock Option Plan.
In June 1998, our shareholders approved the adoption of the 1998
Stock-Based Incentive Plan. The 1998 Stock-Based Incentive Plan authorized up to
1,400,000 shares of our common stock for grants of ISOs and
S-17
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NQSOs, stock appreciation rights, restricted stock awards and bonus stock awards
to our employees or employees of our subsidiaries or associated companies,
subject to the dollar limitations imposed by the Internal Revenue Code. The
exercise price of stock options granted under the plan were no less than the
fair market value of our common stock on the date of grant. 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 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, subject
to the dollar limitations imposed by the Internal Revenue Code. In
the event of a change in control of our company, all outstanding
options become immediately exercisable to the extent permitted by
the plan. Options granted 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, or they vest ratably over a three-year
period, 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. These were the only
compensation plans in effect that were adopted without the approval
of the Company's stockholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS*
* Reference is made to information under the captions "Election of Directors",
"Executive Officers", "Executive Compensation", "Stock Ownership", and "Certain
Relationships and Related Transactions" in our Proxy Statement for the 2003
Annual Meeting of Shareholders.
ITEM 14. CONTROLS AND PROCEDURES
In its recent Release No. 34-46427, effective August 29, 2002, the SEC, among
other things, adopted rules requiring reporting companies to maintain disclosure
controls and procedures to provide reasonable assurance that a registrant is
able to record, process, summarize and report the information required in the
registrant's quarterly and annual reports under the Securities Exchange Act of
1934 (the "Exchange Act"). While we believe that our existing disclosure
controls and procedures have been effective to accomplish these objectives, we
intend to continue to examine, refine and formalize our disclosure controls and
procedures and to monitor ongoing developments in this area.
Our principal executive officer and our principal financial officer have
informed us that, based upon their evaluation as of December 31, 2002, of our
disclosure controls and procedures (as defined in Rule 13a-14(c) and Rule
15d-14(c) under the Exchange Act), they have concluded that those disclosure
controls and procedures are effective.
38
There have been no changes in our internal controls or in other factors known to
us that could significantly affect these controls subsequent to their
evaluation, nor any corrective actions with regard to significant deficiencies
and material weaknesses.
39
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Index to Financial Statements: Page
----
Report of Independent Accountants .................................S-1
Consolidated Balance Sheets at December 31, 2002 and 2001..........S-2
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001 and 2000...................................S-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2002, 2001, and 2000......................S-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001, and 2000..................................S-5
Notes to Consolidated Financial Statements.........................S-7
2. Consolidated Financial Statement Schedules:
Schedule II - Valuation and Qualifying Accounts
Schedule III - Financial Statements and Notes for LLC Geoilbent
All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or the notes
thereto.
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 (Incorporated by reference to Exhibit 3.3 to
our Form 10-Q, filed August 13, 2001).
4.1 Form of Common Stock Certificate (Previously filed as an
exhibit to our S-1 Registration Statement (Registration No.
33-26333)).
4.2 Certificate of Designation, Rights and Preferences of the
Series B. Preferred Stock of Benton Oil and Gas Company,
filed May 12, 1995. (Previously filed as an Exhibit 4.1 to
our Form 10-Q filed on May 13, 2002, File No. 1-10762.)
4.3 Rights Agreement between Benton Oil and Gas Company and
First Interstate Bank, Rights Agent dated April 28, 1995.
(Previously filed as Exhibit 4.1 to our Form 10-Q filed on
August 13, 2002, File No. 1-10762.)
10.1 Form of Employment Agreements (Exhibit 10.19) (Previously
filed as an exhibit to our S-1 Registration Statement
(Registration No. 33-26333)).
10.2 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)).
40
10.3 Operating Service Agreement between Benton Oil and Gas
Company 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)).
10.4 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, File No. 1-10762.)
10.5 Note payable agreement dated March 8, 2001 between
Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a
note in the principal amount of $6,000,000 with interest at
LIBOR plus five percent, for financing of Tucupita Pipeline
(Incorporated by reference to Exhibit 10.24 to our Form
10-Q, filed on May 15, 2001, File No. 1-10762).
10.6 Note payable agreement dated March 8, 2001 between
Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a
note in the principal amount of 4,435,200,000 Venezuelan
Bolivars (approximately $6.3 million) at a floating interest
rate, for financing of Tucupita Pipeline (Incorporated by
reference to Exhibit 10.25 to our Form 10-Q, filed on May
15, 2001, File No. 1-10762.).
10.7 Change of Control Severance Agreement effective May 4, 2001
(Incorporated by reference to Exhibit 10.26 to our Form
10-Q, filed on August 13, 2001, File No. 1-10762.).
10.8 Alexander E. Benton Settlement and Release Agreement
effective May 11, 2001 (Incorporated by reference to Exhibit
10.27 to our Form 10-Q, filed on August 13, 2001, File No.
1-10762.).
10.9 First Amendment to Change of Control Severance Plan
effective June 5, 2001 (Incorporated by reference to Exhibit
10.31 to our Form 10-Q, filed on August 13, 2001, File No.
1-10762.).
10.10 Sale and Purchase Agreement dated February 27, 2002 between
Benton Oil and Gas Company and Sequential Holdings Russian
Investors Limited regarding the sale of Benton Oil and Gas
Company's 68 percent interest in Arctic Gas Company.
(Incorporated by reference to Exhibit 10.25 to our Form 10-K
filed on March 28, 2002, File No. 1-10762.)
10.11 2001 Long Term Stock Incentive Plan (Incorporated by
reference to Exhibit 4.1 to our S-8 (Registration Statement
No. 333-85900)).
10.12 Subordinated Loan Agreement US$2,500,000 between Limited
Liability Company "Geoilbent" as borrower, and Harvest
Natural Resources, Inc. as lender. (Incorporated by
reference to Exhibit 10.2 to our Form 10-Q filed on August
13, 2002.)
10.13 Addendum No. 2 to Operating Services Agreement Monagas SUR
dated 19th September, 2002. (Incorporated by reference to
Exhibit 10.4 to our Form 10-Q filed on November 8, 2002,
File No. 1-10762.)
10.14 Bank Loan Agreement between Banco Mercantil, C.A. and
Benton-Vinccler C.A. dated October 1, 2002. (Incorporated by
reference to Exhibit 10.5 to our Form 10-Q filed on November
8, 2002, File No. 1-10762.)
10.15 Guaranty issued by Harvest Natural Resources, Inc. dated
September 26, 2002. (Incorporated by reference to Exhibit
10.6 to our Form 10-Q filed on November 8, 2002, File No.
1-10762.)
10.16 Amending and Restating the Credit Agreement between Limited
Liability Company "Geoilbent" and European Bank for
Reconstruction and Development dated 23rd September 2002.
(Incorporated by reference to Exhibit 10.7 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)
41
10.17 Amendment Agreement relating to Performance, Subordination
and Share Retention Agreement dated 30th September, 2002.
(Incorporated by reference to Exhibit 10.8 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)
10.18 Amending and Restating the Agreement for Pledge of Shares in
Limited Liability Company "Geoilbent" dated 23rd June, 1997.
(Incorporated by reference to Exhibit 10.9 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)
10.19 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Peter J. Hill. (Incorporated by
reference to Exhibit 10.10 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)
10.20 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Steven W. Tholen. (Incorporated
by reference to Exhibit 10.11 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)
10.21 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Kerry R. Brittain. (Incorporated
by reference to Exhibit 10.12 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)
10.22 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by
reference to Exhibit 10.13 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)
21.1 List of subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP. - Houston
23.2 Consent of ZAO PricewaterhouseCoopers - Moscow
23.3 Consent of Ryder Scott Company, L.P.
(b) Reports on Form 8-K
On December 11, 2002, we filed an 8-K for a press release dated
December 10, 2002, announcing the implementation of an operational contingency
plan for the Company's operations in Venezuela.
On December 19, 2002, we filed an 8-K for a press release dated
December 18, 2002, reporting that, as a result of the ongoing disruptions in
Venezuela, the Company is proceeding with its previously announced operational
contingency plan for its operations in Venezuela.
42
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Stockholders of Harvest Natural Resources, Inc.
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of stockholders' equity and of cash flows
present fairly, in all material respects, the financial position of Harvest
Natural Resources, Inc. and its subsidiaries at December 31, 2002 and 2001, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the related financial statement Schedule II - Valuation and Qualifying Accounts
listed in the index appearing under Item 15(a)(2) on page 40 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 consolidated financial statements, the Company's
total consolidated revenues relate to operations in Venezuela. In addition, the
Venezuelan government has implemented foreign currency controls and its economic
activities have been impacted by national work stoppages.
PricewaterhouseCoopers LLP
Houston, Texas
March 28, 2003
S-1
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-------------------------------
2002 2001
----------- -----------
(IN THOUSANDS, EXCEPT PER
SHARE DATA)
ASSETS
Current Assets:
Cash and cash equivalents.................................................... $ 64,501 $ 9,024
Deposits and restricted cash................................................. 1,812 12
Marketable securities........................................................ 27,388 --
Accounts and notes receivable:
Accrued oil sales......................................................... 27,359 23,138
Joint interest and other, net............................................. 8,002 9,520
Prepaid expenses and other................................................... 2,969 1,839
----------- -----------
Total Current Assets................................................... 132,031 43,533
Restricted Cash................................................................. 16 16
Other Assets.................................................................... 2,520 4,718
Deferred Income Taxes........................................................... 4,082 57,700
Investments In and Advances To Affiliated Companies............................. 51,783 100,498
Property and Equipment:
Oil and gas properties (full cost method-costs of $2,900 and $16,808
excluded from amortization in 2002 and 2001, respectively)................ 576,601 533,950
Furniture and fixtures....................................................... 7,503 7,399
----------- -----------
584,104 541,349
Accumulated depletion, depreciation, and amortization........................ (439,344) (399,663)
----------- -----------
Net Property and Equipment............................................. 144,760 141,686
----------- -----------
$ 335,192 $ 348,151
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable, trade and other............................................ $ 3,804 $ 8,132
Accrued expenses............................................................. 20,644 25,840
Accrued interest payable..................................................... 1,405 3,894
Income taxes payable......................................................... 6,880 3,821
Commodity hedging contract................................................... 430 --
Current portion of long-term debt............................................ 1,867 2,432
----------- -----------
Total Current Liabilities.............................................. 35,030 44,119
Long-Term Debt.................................................................. 104,700 221,583
Commitments and Contingencies................................................... -- --
Minority Interest............................................................... 24,145 14,826
Stockholders' Equity:
Preferred stock, par value $0.01 a share; Authorized 5,000 shares;
outstanding, none Common stock, par value $0.01 a share; Authorized 80,000
shares at December 31, 2002 and 2001; issued 35,900 and 34,164 at
December 31, 2002 and 2001................................................... 359 342
Additional paid-in capital................................................... 173,559 168,108
Retained earnings (accumulated deficit)...................................... 234 (100,128)
Treasury stock, at cost, 650 shares and 50, respectively..................... (2,835) (699)
----------- -----------
Total Stockholders' Equity............................................. 171,317 67,623
----------- -----------
$ 335,192 $ 348,151
=========== ===========
See accompanying notes to consolidated financial statements.
S-2
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
REVENUES
Oil sales......................................................... $ 127,015 $ 122,386 $ 140,284
Loss on ineffective hedge activity................................ (284) -- --
----------- ----------- -----------
126,731 122,386 140,284
----------- ----------- -----------
EXPENSES
Operating expenses................................................ 33,950 42,759 47,430
Depletion, depreciation and amortization.......................... 26,363 25,516 17,175
Write-down of oil and gas properties and impairments.............. 14,537 468 1,346
General and administrative........................................ 16,504 20,072 16,739
Bad debt recovery................................................. (3,276) -- --
Taxes other than on income........................................ 4,068 5,370 4,390
----------- ----------- -----------
92,146 94,185 87,080
----------- ----------- -----------
Income from Operations............................................... 34,585 28,201 53,204
Other Non-Operating Income (Expense)
Gain on sale of investment........................................ 144,029 -- --
Gain on early extinguishment of debt.............................. 874 -- 3,960
Investment earnings and other..................................... 2,080 3,088 8,559
Interest expense.................................................. (16,310) (24,875) (28,973)
Net gain on exchange rates........................................ 4,553 768 326
----------- ----------- -----------
135,226 (21,019) (16,128)
----------- ----------- -----------
Income from Consolidated Companies Before Income
Taxes and Minority Interest....................................... 169,811 7,182 37,076
Income Tax Expense (Benefit)......................................... 60,295 (35,698) 14,032
----------- ----------- -----------
Income Before Minority Interest...................................... 109,516 42,880 23,044
Minority Interest in Consolidated Subsidiary Companies............... 9,319 5,545 7,869
----------- ----------- -----------
Income from Consolidated Companies................................... 100,197 37,335 15,175
Equity in Net Earnings of Affiliated Companies....................... 165 5,902 5,313
----------- ----------- -----------
Net Income........................................................... $ 100,362 $ 43,237 $ 20,488
=========== =========== ===========
Net Income Per Common Share:
Basic............................................................ $ 2.90 $ 1.27 $ 0.67
=========== =========== ===========
Diluted.......................................................... $ 2.78 $ 1.27 $ 0.66
=========== =========== ===========
See accompanying notes to consolidated financial statements.
S-3
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)
RETAINED
COMMON ADDITIONAL EARNINGS
SHARES COMMON PAID-IN (ACCUMULATED TREASURY
ISSUED STOCK CAPITAL DEFICIT) STOCK TOTAL
----------- ----------- ----------- ----------- ----------- -----------
BALANCE AT JANUARY 1, 2000.... 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
Issuance of common shares:
Non-employee director
compensation............. 292 3 471 - - 474
Tax benefits related to stock
option compensation......... - - 11,008 - - 11,008
Net Income.................... - - - 43,237 - 43,237
----------- ----------- ----------- ---------- ----------- -----------
BALANCE AT DECEMBER 31, 2001.. 34,164 342 $ 168,108 $ (100,128) $ (699) $ 67,623
Issuance of common shares:
Non-employee director
compensation............. 46 - 543 - - 543
Employee compensation...... 175 2 663 - - 665
Exercise of stock options.. 1,515 15 4,245 - - 4,260
Treasury stock (600 shares)... - - - - (2,136) (2,136)
Net Income.................... - - - 100,362 - 100,362
----------- ----------- ----------- ---------- ----------- -----------
BALANCE AT DECEMBER 31, 2002.. 35,900 $ 359 $ 173,559 $ 234 $ (2,835) $ 171,317
=========== =========== =========== ========== =========== ===========
See accompanying notes to consolidated financial statements.
S-4
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
YEARS ENDED DECEMBER 31,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(IN THOUSANDS)
Cash Flows From Operating Activities:
Net income ....................................................... $ 100,362 $ 43,237 $ 20,488
Adjustments to reconcile net income to net cash provided by
operating activities:
Depletion, depreciation and amortization....................... 26,363 25,516 17,175
Write-down and impairment of oil and gas properties............ 14,537 468 1,346
Amortization of financing costs................................ 1,745 1,179 1,375
(Gain) loss on disposition of assets........................... (144,029) (336) 60
Equity in net earnings of affiliated companies................. (165) (5,902) (5,313)
Allowance and write-off of employee notes and accounts
receivable................................................... (2,987) 365 331
Non-cash compensation related charges.......................... 1,458 474 --
Minority interest in undistributed earnings of subsidiaries.... 9,319 5,545 7,869
Gain from early extinguishment of debt......................... (874) -- (3,960)
Tax benefits related to stock option compensation.............. -- 11,008 --
Deferred income taxes.......................................... 53,618 (53,407) 7,893
Changes in operating assets and liabilities:
Accounts and notes receivable.................................. (1,972) 11,756 (12,780)
Prepaid expenses and other..................................... (1,130) 565 (769)
Accounts payable............................................... (4,328) (4,671) 9,487
Accrued interest payable....................................... (2,489) 161 (953)
Accrued expenses............................................... (10,290) 43 7,971
Commodity hedging contract..................................... 430 -- --
Income taxes payable........................................... 3,059 607 1,543
----------- ----------- -----------
Net Cash Provided by Operating Activities...................... 42,627 36,608 51,763
----------- ----------- -----------
Cash Flows from Investing Activities:
Proceeds from sale of investment.................................. 189,841 -- 800
Additions of property and equipment............................... (43,346) (43,364) (57,196)
Investment in and advances to affiliated companies................ 9,185 (16,855) (11,071)
Increase in restricted cash....................................... (2,800) (57) (271)
Decrease in restricted cash....................................... 1,000 10,961 35,800
Purchases of marketable securities................................ (353,478) (15,067) (12,638)
Maturities of marketable securities............................... 326,090 16,370 15,804
----------- ----------- -----------
Net Cash Provided by (Used In) Investing Activities............ 126,492 (48,012) (28,772)
----------- ----------- -----------
Cash Flows from Financing Activities:
Net proceeds from exercise of stock options....................... 3,345 -- 330
Proceeds from issuance of short term borrowings and notes
payable......................................................... 15,500 21,112 15,087
Payments on short term borrowings and notes payable............... (132,138) (15,746) (47,488)
(Increase) decrease in other assets............................... (349) (70) 3,065
----------- ----------- -----------
Net Cash Provided by (Used In) Financing Activities............ (113,642) 5,296 (29,006)
----------- ----------- -----------
Net Increase (Decrease) in Cash and Cash Equivalents........... 55,477 (6,108) (6,015)
Cash and Cash Equivalents at Beginning of Year....................... 9,024 15,132 21,147
----------- ----------- -----------
Cash and Cash Equivalents at End of Year............................. $ 64,501 $ 9,024 $ 15,132
=========== =========== ===========
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for interest expense.................... $ 19,201 $ 25,721 $ 28,326
=========== =========== ===========
Cash paid during the year for income taxes........................ $ 3,935 $ 3,057 $ 2,950
=========== =========== ===========
See accompanying notes to consolidated financial statements.
S-5
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
For the three years ended December 31, 2002, we recorded an allowance for
doubtful accounts related to interest accrued on the remaining amount owed to us
by our former chief executive officer, A. E. Benton. During the year ended
December 31, 2002, we reversed a portion of such allowance as a result of our
collection of certain amounts owed to the Company including the portions of the
note secured by our stock and other properties (see Note 13 - Related Party
Transactions).
See accompanying notes to consolidated financial statements.
S-6
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Harvest Natural Resources, Inc. (formerly known as Benton Oil and Gas Company)
is engaged in the exploration, development, production and management of oil and
gas properties. We conduct our business principally in Venezuela and through our
equity interest in our entity in Russia.
PRINCIPLES OF CONSOLIDATION
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 LLC Geoilbent ("Geoilbent") and Arctic Gas Company
("Arctic Gas"), based on a fiscal year ending September 30 (see Note 2 -
Investments In and Advances to Affiliated Companies).
REVENUE RECOGNITION
Oil revenue is accrued monthly based on production and delivery. Each quarter,
Benton-Vinccler invoices PDVSA or affiliates based on barrels of oil accepted by
PDVSA during the quarter, using quarterly adjusted U.S. dollar contract service
fees per barrel. The operating service agreement provides for Benton-Vinccler to
receive an operating fee for each barrel of crude oil delivered and 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.
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 cost. The marketable securities we may
purchase are limited to those defined as Cash Equivalents in the indentures for
our senior unsecured note. 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 $27.4 million in commercial paper at December 31, 2002.
CREDIT RISK AND OPERATIONS
All of our total consolidated revenues relate to operations in Venezuela. During
the year ended December 31, 2002, our Venezuelan crude oil production
represented all of its total production from consolidated companies, and our
sole source of revenues related to such Venezuelan production is PDVSA, which
maintains full ownership of all hydrocarbons in its fields. On December 2, 2002,
employers' and workers' organizations, together with political and civic
organizations began a national civic work stoppage, which has seriously affected
many of the country's economic activities, in particular, the oil industry. As a
result of the strike, we were unable to deliver crude oil and
S-7
hence generate revenues from PDVSA between December 14, 2002 and February 6,
2003. While Venezuelan production has resumed and we have received payment for
its revenues from PDVSA, there continues to be political and economic
uncertainty that could lead to another disruption of our revenues. Further, on
January 21, 2003, the Venezuelan Government has closed foreign currency markets
and announced its intention to implement currency exchange controls aimed at
restricting the convertibility of the Venezuelan Bolivar and the transfer of
funds out of Venezuela. The Venezuelan Government has created a new Currency
Exchange Agency ("CADIVI") which will be responsible for the administration of
exchange controls. The closure of the foreign currency markets has limited
Benton-Vinccler's ability to obtain Bolivars to make payments to employees and
vendors and has restricted our ability to repatriate funds from Venezuela in
order to meet our cash requirements. Detailed regulations for exchange controls
have not yet been issued by CADIVI. It is not possible to estimate the effects
that any further disruptions in Venezuelan crude oil sales or that prolonged
currency controls could have on operations and results. Management believes that
we have sufficient cash and does not expect the currency conversion restrictions
to adversely affect our ability to meet our short-term obligations.
DERIVATIVES AND HEDGING
We began in the third quarter of 2002 to use a derivative instrument to manage
market risk resulting from fluctuations in the commodity price of crude oil.
Benton-Vinccler, C.A. (See Note 10 - Venezuelan Operations) entered into a
commodity contract (costless collar), which requires payments to (or receipts
from) counterparties based on a West Texas Intermediate crude oil floor price of
$23.00 and a ceiling price of $30.15 for 6,000 barrels of oil per day. The
notional amount of this financial instrument is based on expected sales of crude
oil production from drilling of the Tucupita development wells. This instrument
protects our projected investment return by reducing the impact of an unexpected
downward crude oil price movement. The hedge covers expected sales of production
for six months beginning in mid-August 2002. Due to the pricing structure of our
Venezuelan oil, this collar had the economic effect of hedging approximately
12,000 barrels of oil per day until sales were ceased on December 14, 2002, due
to the Venezuelan national civil work stoppage. In order for a derivative
instrument to qualify for hedge accounting, there must have been a clear
correlation between the derivative instrument and the forecasted transaction.
Correlation of the commodity contract was determined by evaluating whether the
contract gains and losses would substantially offset the effects of price
changes on the underlying crude oil sales volumes. To the extent that
correlation exists between the contract and the underlying crude oil sales
volumes, realized gains or losses and related cash flows arising from the
contracts are recognized as a component of oil revenue in the same period as the
sale of the underlying volumes.
This derivative contract has been designated as a cash flow hedge. For all
derivatives designated as cash flow hedges, we formally document the
relationship between the derivative contract and the hedged item, as well as the
risk management objective for entering into the contract. To be designated as a
cash flow hedge transaction, the relationship between the derivative and the
hedged item must be highly effective in achieving the offset of changes in cash
flows attributable to the risk both at the inception of the derivative and on an
ongoing basis. We measure the hedge effectiveness on a quarterly basis and hedge
accounting is discontinued prospectively if it is determined that the derivative
is no longer effective in offsetting changes in the cash flows of the hedged
item.
Statement of Financial Accounting Standards No. 133, as amended, establishes
accounting and reporting standards for derivative instruments and hedging
activities. All derivatives are recorded on the balance sheet at fair value. To
the extent that the hedge is determined to be effective, as discussed above,
changes in the fair value of derivatives for cash flow hedges are recorded each
period in other comprehensive income. Our derivative is a cash flow hedge
transaction in which we hedge the variability of cash flows related to a
forecasted transaction. This derivative instrument was designated as a cash flow
hedge and the changes in the fair value will be reported in other comprehensive
income assuming the highly effective test is met, and has been reclassified to
earnings in the period in which earnings are impacted by the variability of the
cash flows of the hedged item. We determined that the underlying crude oil would
not be delivered due to the cessation of production. Accordingly, hedge
accounting was discontinued and the value of the derivative was recorded as a
revenue reduction in the amount of $0.3 million. In connection with this
instrument we had deposited collateral of $1.8 million as of December 31, 2002
with the counterparty.
S-8
ACCOUNTS AND NOTES RECEIVABLE
Allowance for doubtful accounts related to former employee notes at December 31,
2002 and 2001 was $3.5 million and $6.2 million, respectively (see Note 13 -
Related Party Transactions).
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.
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 $0.6
million and $1.5 million for the years ended December 31, 2001 and 2000,
respectively, and capitalized interest of $0.9 million and $0.6 million for the
years ended December 31, 2001 and 2000, respectively. There was no capitalized
overhead and interest in 2002. 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 2002, 2001
and 2000, the Company recognized $14.5 million, $0.5 million and $1.3 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, 2002 consisted of the following by year incurred
(in thousands):
PRIOR
TOTAL TO 2000
--------- ---------
Property acquisition costs...................... $ 2,900 $ 2,900
========= =========
All of the excluded costs at December 31, 2002 relate to the acquisition of
Benton Offshore China Company and exploration related to its WAB-21 property.
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,
2002, 2001 and 2000 was $24.9 million, $22.1 million and $15.3 million ($2.56,
$2.26 and $1.68 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 $1.4 million, $3.4
million and $1.8 million for the years ended December 31, 2002, 2001 and 2000,
respectively.
S-9
The major components of property and equipment at December 31 are as follows (in
thousands):
2002 2001
----------- -----------
Proved property costs................................... $ 566,415 $ 501,923
Costs excluded from amortization........................ 2,900 16,808
Material and supply inventories......................... 7,286 15,219
Furniture and fixtures.................................. 7,503 7,399
----------- -----------
584,104 541,349
Accumulated depletion, impairment and depreciation...... (439,344) (399,663)
----------- -----------
$ 144,760 $ 141,686
=========== ===========
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.
No ceiling test write-downs were required.
INCOME TAXES
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. In
the fourth quarter of 2001, a substantial portion of the valuation allowance was
reversed based on the utilization of net operating losses by the Arctic Gas Sale
in 2002.
FOREIGN CURRENCY
We have significant operations outside of the United States, principally in
Venezuela and an equity investment in Russia. Amounts denominated in non-U.S.
currencies 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 that 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.
In November 2002, the International Practices Task Force (IPTF) concluded that
Russia has ceased being a highly inflationary economy as of January 1, 2003. As
a result of the Task Force conclusion, companies reporting under US GAAP in
Russia will be required to apply the guidance contained in EITF No. 92-4 and
EITF No. 92-8 as of January 1, 2003. We have not yet estimated the effect that
EITF No. 92-4 and EITF No. 92-8 will have on Geoilbent or our equity position.
FINANCIAL INSTRUMENTS
Our financial instruments that are exposed to concentrations of credit risk
consist primarily of cash and cash equivalents, marketable securities and
accounts receivable. Cash and cash equivalents are placed with commercial banks
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
purchases 100 percent of our Venezuelan oil and gas production. Although the
Company does not currently foresee a credit risk associated with these
receivables, collection is dependent upon the financial stability of PDVSA. The
payment for the fourth quarter 2002 sales was delayed until March 7, 2003, which
was approximately seven days late due to the effect of the national civil work
stoppage on PDVSA.
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, 2002 and 2001, was approximately $77.4 million and $138.1
million, respectively.
S-10
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, 2002 and, in accordance with SFAS 130, have not provided a separate
statement of comprehensive income.
MINORITY INTERESTS
We record a minority interest attributable to the minority shareholder of our
Venezuela subsidiaries. The minority interests in net income and losses are
generally subtracted or added to arrive at consolidated net income.
NEW ACCOUNTING PRONOUNCEMENTS
In September 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method. SFAS No. 143 is
effective for fiscal years beginning after September 15, 2002. We will adopt
SFAS No. 143 effective January 1, 2003 and such adoption will not materially
impact the financial statements since our PDVSA operating service agreement
provides that all wells revert to PDVSA at contract expiration and intervening
abandonment obligations are minor. Accordingly, all gains on early
extinguishment of debt have been reclassified to other non-operating income in
the accompanying consolidated financial statements.
In May 2002, the FASB issued SFAS No. 145, Recission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS
145 rescinds the automatic treatment of gains or losses from extinguishment of
debt as extraordinary items as outlined in APB Opinion No. 30, "Reporting the
Results of Operations, Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions". As allowed under the provisions of SFAS 145, we had decided to
adopt SFAS 145 early (See Note 3 - Long Term Debt and Liquidity).
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities". The standard requires companies to recognize
costs associated with exit or disposal activities when they are incurred rather
than at the date of a commitment to an exit or disposal plan. Examples of costs
covered by the standard include lease termination costs and certain employee
severance costs that are associated with a restructuring, discontinued
operation, plant closing, or other exit or disposal activity. SFAS 146 replaces
Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)". The provisions of this statement
shall be effective for exit or disposal activities initiated after December 31,
2002. The Company will account for exit or disposal activities initiated after
December 31, 2002, in accordance with the provisions of SFAS No. 146.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure an amendment of FASB Statement No.
123". The standard amends SFAS No. 123 that provides alternative methods of
transition for an entity that voluntarily changes to the fair value based method
of accounting for stock-based employee compensation. In addition, this statement
amends the disclosure requirements of SFAS No. 123 to require prominent
disclosures in both annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the method
used on reported results. The Company intends to adopt the "Prospective method"
which will apply the recognition provisions to all employee awards granted,
modified, or settled in 2003.
The weighted average fair value of the stock options granted from our stock
option plans during 2002, 2001 and 2000 was $4.84, $1.33 and $1.65,
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:
S-11
2002 2001 2000
----------- ----------- -----------
Expected life............................... 10.0 years 10.0 years 9.1 years
Risk-free interest rate..................... 5.0% 5.1% 6.1%
Volatility.................................. 74% 72% 74%
Dividend Yield.............................. 0% 0% 0%
We accounted 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 2002, 2001 and 2000 would have been as follows
(in thousands, except per share data):
2002 2001 2000
--------- --------- ---------
Net income as reported................................. $ 100,362 $ 43,237 $ 20,488
Add: Stock-based employee compensation expense
included in reported net income due to acceleration
of vesting of former employees......................... 915 35 110
Deduct: Total stock-based employee compensation
expense determined under fair value based method for
all grants awarded since January 1, 1995............... (2,905) (2,459) (4,374)
--------- --------- ---------
Net income ............................................ $ 98,372 $ 40,813 $ 16,224
========= ========= =========
Net income per common share:
Basic............................................... $ 2.87 $ 1.20 $ 0.53
========= ========= =========
Diluted............................................. $ 2.75 $ 1.20 $ 0.53
========= ========= =========
In November 2002 FASB interpretation, or FIN 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantee of
Indebtedness of Others" was issued. FIN 45 requires that upon issuance of a
guarantee, the guarantor must recognize a liability for the fair value of the
obligation it assumes under that guarantee. FIN 45's provisions for initial
recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's initial
application may not be revised or restated to reflect the effect of the
recognition and measurement provisions of FIN 45. The disclosure requirements
are effective for financial statements of both interim and annual periods that
end after December 15, 2002. As of December 31, 2002, the Company does not have
any guarantor obligations.
In January 2003 FASB Interpretation 46, or FIN 46, "Consolidation of Variable
Interest Entities" was issued. FIN 46 identifies certain off-balance sheet
arrangements that meet the definition of a variable interest entity (VIE). The
primary beneficiary of a VIE is the party that is exposed to the majority of the
risks and/or returns of the VIE. In future accounting periods, the primary
beneficiary will be required to consolidate the VIE. In addition, more extensive
disclosure requirements apply to the primary beneficiary, as well as other
significant investors. We do not believe we participate in any arrangement that
would be subject to the provisions of FIN 46.
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. The most significant estimates pertain to proved
oil, plant products and gas reserve volumes and the future development costs.
Actual results could differ from those estimates.
S-12
RECLASSIFICATIONS
Certain items in 2000 and 2001 have been reclassified to conform to the 2002
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. Arctic Gas was sold on April 12, 2002.
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
--------------------- --------------------- ---------------------
2002 2001 2002 2001 2002 2001
--------- --------- --------- --------- -------- ---------
Investments:
In equity in net assets........... $ 28,056 $ 28,056 $ -- $ (1,814) $ 28,056 $ 26,242
Other costs, net of amortization.. 263 (99) -- 28,579 263 28,480
--------- --------- --------- --------- -------- ---------
Total investments................. 28,319 27,957 -- 26,765 28,319 54,722
Advances.............................. 2,527 - -- 28,829 2,527 28,829
Equity in earnings (losses)........... 20,937 19,307 -- (2,360) 20,937 16,947
--------- --------- --------- --------- -------- ---------
Total.......................... $ 51,783 $ 47,264 $ -- $ 53,234 $ 51,783 $ 100,498
========= ========= ========= ========= ======== =========
NOTE 3 - LONG-TERM DEBT AND LIQUIDITY
LONG-TERM DEBT
Long-term debt consists of the following (in thousands):
DECEMBER 31, DECEMBER 31,
2002 2001
------------ ------------
Senior unsecured notes with interest at 9.375%
See description below................................ $ 85,000 $ 105,000
Senior unsecured notes with interest at 11.625%
See description below................................ -- 108,000
Note payable with interest at 6.8%
See description below................................ 3,900 5,100
Note payable with interest at 39.7%
See description below................................ 2,167 5,235
Note payable with interest at 7.8%........................ 15,500 --
Non-interest bearing liability with a face value of $744
discounted at 7%. See description below............. -- 680
----------- -----------
106,567 224,015
Less current portion...................................... 1,867 2,432
----------- -----------
$ 104,700 $ 221,583
=========== ===========
At December 31, 2001, we had $108.0 million in 11.625 percent senior unsecured
notes due in May 1, 2003, all of which have been redeemed, which resulted in a
gain of $0.9 million in 2002. In November 1997, we issued $115.0 million in
9.375 percent senior unsecured notes due November 1, 2007 ("2007 Notes"), of
which we repurchased $30.0 million. Interest on the 2007 Notes is due May 1 and
November 1 of each year. At December 31, 2002, we were in compliance with all
covenants of the indenture.
In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan
commercial bank, for construction of an oil pipeline. The loan is in two parts,
with the first part in an original principal amount of $6.0 million that bears
S-13
interest payable monthly based on 90-day London Interbank Borrowing Rate
("LIBOR") plus 5 percent with principal payable quarterly for five years. The
second part, in the original principal amount of 4.4 billion Venezuelan Bolivars
("Bolivars") (approximately $6.3 million), bears interest payable monthly based
on a mutually agreed interest rate determined quarterly, or a six-bank average
published by the central bank of Venezuela. The interest rate for the quarter
ending December 31, 2002 was 39.7 percent with a negative effective interest
rate taking into account exchange gains resulting from the devaluation of the
Bolivar during the year. The loans provide for certain limitations on mergers
and sale of assets. The Company has guaranteed the repayment of this loan
On October 1, 2002, Benton-Vinccler, C.A. executed a note and borrowed $15.5
million to fund construction of a gas pipeline and related facilities to deliver
natural gas from the Uracoa field to a PDVSA pipeline. The interest rate for
this loan is LIBOR plus 6 percentage points determined quarterly. The term is
four years with a one year debt service grace period to coincide with our gas
sales and a quarterly amortization of $1.3 million.
Benton-Vinccler's oil and gas pipeline project loans allow the lender to
accelerate repayment if production ceases for a period greater than thirty days.
During the production shut-in which started in December 2002, Benton-Vinccler
was granted a waiver of this provision until February 18, 2003 for a prepayment
of the next two principal obligations aggregating $0.9 million. This prepayment,
while using cash reserves, reduces our net interest expense as the current
interest expense was more than the current interest income earned on the
invested funds. On February 8, 2003, Benton-Vinccler commenced production,
thereby eliminating the need for an additional waiver. A future disruption of
production could trigger the debt acceleration provision again. While no
assurances can be given, we believe Benton-Vinccler would be able to obtain
another waiver.
In 2001, a dispute arose over collection by municipal taxing regimes on the
Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit
resulting in overpayments and underpayments to adjacent municipalities. As
settlement, a portion of future municipal tax payments will be offset by the
municipal tax that was originally overpaid. The present value of the long-term
portion of the settlement liability is $0.7 million at December 31, 2001. The
entire balance was repaid by December 31, 2002.
The principal payment requirements for our long-term debt outstanding at
December 31, 2002 are as follows (in thousands):
2003.......................................................... $ 1,867
2004.......................................................... 7,035
2005.......................................................... 7,035
2006.......................................................... 5,630
2007.......................................................... 85,000
-----------
$ 106,567
===========
LIQUIDITY
We currently have a significant debt obligation payable in November 2007 of $85
million. Our ability to meet our debt obligations and to reduce our level of
debt depends on the successful implementation of our strategic objectives. Our
cash flow from operations complemented with our cash and cash equivalents of
$91.9 million at December 31, 2002, can be invested in other opportunities used
to develop our significant proved undeveloped reserves or used to repurchase our
outstanding debt.
NOTE 4 - COMMITMENTS AND CONTINGENCIES
We have employment contracts with four executive officers which provide for
annual base salaries, eligibility for bonus compensation and various benefits.
The contracts provide for a lump sum payment as a multiple of base salary in the
event of termination of employment without cause. In addition, these contracts
provide for payments as a multiple of base salary and bonus, tax reimbursement
and a continuation of benefits in the event of termination without cause
following a change in control of the Company. By providing one year notice,
these agreements may be terminated by either party on May 31, 2004.
S-14
In July 2001, we leased for three years office space in Houston, Texas for
approximately $11,000 per month. We lease 17,500 square feet of space in a
California building that we no longer occupy under a lease agreement that
expires in December 2004, all of which has been subleased for rents that
approximate our lease costs.
The Company is a defendant in or otherwise involved in litigation incidental to
its business. In the opinion of management, there is no litigation which is
material to the Company.
NOTE 5 - TAXES
TAXES OTHER THAN ON INCOME
Benton-Vinccler pays a municipal tax on operating fee revenues it receives for
production from the South Monagas Unit. The components of taxes other than on
income were (in thousands):
2002 2001 2000
--------- --------- ---------
Venezuelan municipal taxes........................... $ 3,805 $ 4,447 $ 3,164
Severance and production taxes....................... - - 28
Franchise taxes...................................... 139 121 131
Payroll and other taxes.............................. 124 802 1,067
--------- --------- ---------
$ 4,068 $ 5,370 $ 4,390
========= ========= =========
TAXES ON INCOME
The tax effects of significant items comprising our net deferred income taxes as
of December 31, 2002 and 2001 are as follows (in thousands):
2002 2001
----------- -----------
Deferred tax assets:
Operating loss carryforwards............................... $ 19,690 $ 49,000
Difference in basis of property............................ 21,495 19,300
Other...................................................... 2,043 9,100
Valuation allowance........................................ (39,146) (19,700)
----------- -----------
Net deferred tax asset......................................... $ 4,082 $ 57,700
=========== ===========
The valuation allowance increased by $19.4 million as a result of the increase
in the U.S. deferred tax assets related to the net operating loss carryforward.
Realization of deferred tax assets associated with net operating loss
carryforwards is dependent upon generating sufficient taxable income prior to
their expiration. Management believes it is more likely than not that they will
be realized through future taxable income.
The components of income before income taxes, minority interest and
extraordinary items are as follows (in thousands):
2002 2001 2000
----------- ----------- -----------
Income (loss) before income taxes
United States................................... $ 89,455 $ (26,572) $ (9,074)
Foreign......................................... 80,356 33,754 46,150
----------- ----------- -----------
Total....................................... $ 169,811 $ 7,182 $ 37,076
=========== =========== ===========
S-15
The provision (benefit) for income taxes consisted of the following at December
31, (in thousands):
2002 2001 2000
----------- ----------- -----------
Current:
United States........................................ $ 353 $ 1 $ 215
Foreign.............................................. 6,324 6,700 5,925
----------- ----------- -----------
$ 6,677 $ 6,701 $ 6,140
=========== =========== ===========
Deferred:
United States........................................ $ 53,413 $ (42,405) --
Foreign.............................................. 205 6 7,892
----------- ----------- -----------
53,618 (42,399) 7,892
----------- ----------- -----------
$ 60,295 $ (35,698) $ 14,032
=========== =========== ===========
A comparison of the income tax expense (benefit) at the federal statutory rate
to our provision for income taxes is as follows (in thousands):
2002 2001 2000
---------- ---------- ----------
Computed tax expense at the statutory rate................... $ 59,348 $ 4,580 $ 13,451
State income taxes........................................... 353 -- (343)
Effect of foreign source income and rate differentials on
foreign income........................................... (19,373) 1,675 (1,826)
Change in valuation allowance................................ 19,446 (53,413) 2,294
Prior year adjustments....................................... -- 2,304 1,637
Reclass paid-in capital...................................... -- 11,007 --
All other.................................................... 80 215 679
---------- ---------- ----------
Sub-total income tax expense (benefit)....................... 59,854 (33,632) 15,892
Effects of recording equity income of certain affiliated
Companies on an after-tax basis.......................... 441 (2,066) (1,860)
---------- ---------- ----------
Total income tax expense (benefit)........................... $ 60,295 $ (35,698) $ 14,032
========== ========== ==========
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.
At December 31, 2002, we had, for federal income tax purposes, operating loss
carryforwards of approximately $56.3 million, expiring in the years 2011 through
2022.
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
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.
Under the Stock Purchase Plan each non-employee director could elect to receive
shares of our common stock for all or a portion of their fee for serving as a
director. The number of shares issuable is 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 have a restriction upon their sale for one year from the date of
issuance. As of December 31, 2002, 337,850 shares had been issued from the plan.
The Stock Purchase Plan was terminated by the Board of Directors in September
2002.
In July 2001, our shareholders approved the adoption of the 2001 Long Term Stock
Incentive Plan. The 2001 Long Term Stock Incentive Plan provides for grants of
options to purchase up to 1,697,000 shares of our common stock in the form of
ISOsIncentive Stock Options and NQSOsNon-qualified Stock Options to eligible participants
including employees of our company or subsidiaries, directors, consultants and
other key persons. 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. No officer may be granted
S-16
more than 500,000 options during any one fiscal year, 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 vest ratably
over a three-year period from their dates of grant and expire ten years from
grant date.
The Directors' Stock Option Plan permitted the granting of nonqualifiedSince 1989 we have adopted several other 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, 2001,plans under which options
to purchase 280,000 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 stock for all or a portion of their fee for serving as a
director. The number of shares issuable will behave been granted to employees, officers,
directors, independent contractors and consultants. Options granted under these
plans have been at prices 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 paymentgrant dates. Options granted under the plans are generally exercisable in
varying cumulative periodic installments after one year cannot be exercised more
than ten years after the grant dates. Following the adoption of the applicable director's fee.
The shares will have a restriction upon their sale for one year from the date2001 Long
Term Stock Incentive Plan, no options may be granted under any of issuance. As of December 31, 2001, 292,170 shares had been issued from the plan.
S-18
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)these plans.
A summary of the status of our stock option plans as of December 31, 2002, 2001
2000 and 19992000 and changes during the years ending on those dates is presented below
(shares in thousands):
2002 2001 2000
1999
----------------- ----------------- ----------------------------------- ------------------ ------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
PRICE SHARES PRICE SHARES PRICE SHARES
-------- ------------- -------- ------ -------- ------
Outstanding at beginning of the year:.......................... $7.74 $ 6.36 6,865 $ 7.74 5,660 $7.55$ 7.55 6,300
$11.27 3,712
Options granted..................granted 4.84 165 1.65 1,684 2.06 240
2.37 2,701
Options exercised................exercised 2.21 (1,515) -- -- 2.53 (85)
-- --
Options cancelled................cancelled 8.03 (292) 6.43 (479) 4.90 (795)
6.10 (113)
----- ----- ------------ ------ ------
Outstanding at end of the year...year 7.42 5,223 6.36 6,865 7.74 5,660
7.55 6,300
===== ===== ============ ====== ======
Exercisable at end of the year...year 8.49 4,360 8.32 4,800 9.68 4,099
11.23 3,251
===== ===== ============ ====== ======
Significant option groups outstanding at December 31, 20012002 and related weighted
average price and life information follow:
OUTSTANDING EXERCISABLE
---------------------------------------------------------- --------------------------------------
RANGE OF NUMBER WEIGHTED-AVERAGE NUMBER
EXERCISE OUTSTANDING AT REMAINING WEIGHTED-AVERAGE EXERCISABLE AT WEIGHTED-AVERAGE
PRICES DECEMBER 31, 20012002 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 20012002 EXERCISE PRICE
- ----------------------- ----------------- --------------------------------- ---------------- ----------------- ----------------
$ 1.55-1.55 - $ 2.75........ 3,974,332 8.42 $2.05 1,908,664 $2.322.75 2,475,149 7.70 $ 4.89-1.97 1,737,066 $ 7.00........ 409,333 2.77 6.19 409,333 6.192.09
$ 7.25-4.89 - $11.00........ 903,033 3.17 8.62 903,033 8.62
$11.50- 7.00 520,333 4.38 5.77 395,333 6.07
$16.50........ 1,080,665 4.91 13.59 1,080,665 13.59
$17.38-$24.13........ 497,833 5.05 7.25 - $11.00 660,633 3.16 8.88 660,633 8.88
$11.50 - $16.50 1,071,665 3.91 13.58 1,071,665 13.58
$17.38 - $24.13 494,833 4.05 21.13 497,833494,833 21.13
--------- ---------
6,865,196 4,799,528
========= =========----------- ----------
5,222,613 4,359,530
=========== ==========
The weighted average fair value ofOf the stocknumber outstanding, 1,233,750 options granted from our stock
option plans during 2001, 2000, and 1999 was $1.33, $1.65 and $1.88,
respectively. The fair value of each stock option grant is estimated onare controlled by the date
of grant usingcompany
through the Black-Scholes option pricing model with the following
weighted average assumptions used:
2001 2000 1999
---------- --------- ---------
Expected life....................................... 10.0 years 9.1 years 9.3 years
Risk-free interest rate............................. 5.1% 6.1% 5.9%
Volatility.......................................... 72% 74% 73%
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
S-19
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
income and earnings per share for 2001, 2000 and 1999 would have been as follows
(in thousands, except per share data):
2001 2000 1999
------- ------- --------
Net income (loss)...................................... $40,813 $16,224 $(38,441)
======= ======= ========
Net income (loss) per common share:
Basic................................................ $ 1.20 $ 0.53 $ (1.30)
======= ======= ========
Diluted.............................................. $ 1.20 $ 0.53 $ (1.30)
======= ======= ========
A. E. Benton settlement. See Note 13 - Related Party Transactions.
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, 2001,2002, 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$5.63 to $11.88 which vest over three to four years. At December
31, 2001,2002, a total of 208,500192,500 options issued outside of the plans were both
outstanding and exercisable.
On January 22, 2002, 19,000 of these options
expired. Our expenses associated with these options were not material.S-17
NOTE 7 --- STOCK WARRANTS
The dates the warrants were issued, the expiration dates, the exercise prices
and the number of warrants issued and outstanding at December 31, 20012002 were
(shares(warrants in thousands):
WARRANTS
----------------------------
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING
- ----------- --------------- -------------- -------------- -----------
July 1994...........................1994 July 2004 $ 7.50 150 8
September 1994...................... September 2002 9.00 250 250
December 1994.......................1994 December 2004 12.00 50 50
June 1995...........................1995 June 2007 17.09 125 125
January 1996........................ January 2002 11.00 588 577
----- -----
1,163 1,010
===== =====-------- ---------
325 183
======== =========
NOTE 8 --- OPERATING SEGMENTS
We regularly allocate resources to and assessesassess 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. RevenuesRevenue from
the
Venezuela and Russia operating segments areis 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
S-20
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
administrative and interest expenses are included in the USA and Other segment
and are not allocated to other operating segments.
YEAR ENDED DECEMBER 31, 2002:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
-------------------- ------------- -------- ------------ ------------ (IN THOUSANDS)------------
Revenues
Oil sales............................... $ 127,015 $ - $ - $ - $ 127,015
Other comprehensive loss: hedge......... (284) - - - (284)
----------- ---------- ------------ --------- ---------
126,731 - - - 126,731
----------- ---------- ------------ --------- ---------
Expenses
Operating expenses...................... 31,457 360 2,133 - 33,950
Depletion, depreciation and
amortization.......................... 23,850 2,483 30 - 26,363
General and administrative.............. 4,310 11,420 774 - 16,504
Bad debt recovery....................... - (3,276) - - (3,276)
Taxes other than on income.............. 3,997 71 - - 4,068
----------- ---------- ------------ --------- ---------
Total expenses.................... 63,614 11,058 2,937 - 77,609
----------- ---------- ------------ --------- ---------
Income (loss) from operations............... 63,117 (11,058) (2,937) - 49,122
Other non-operating income (expense)
Gain on sale of investment.............. - 144,032 (3) - 144,029
Gain on early extinguishment of debt.... - 874 - - 874
Investment earnings and other........... 1,889 1,653 - (1,462) 2,080
Interest expense........................ (4,237) (13,611) - 1,538 (16,310)
Net gain on exchange rates.............. 4,356 197 - - 4,553
Intersegment revenues (expenses)........ 15,156 (15,156) - - -
Equity in income of affiliated
companies............................. - - 165 - 165
----------- ---------- ------------ --------- ---------
17,164 117,989 162 76 135,391
----------- ---------- ------------ --------- ---------
Income (loss) before income taxes........... 80,281 106,931 (2,775) 76 184,513
Income tax expense.......................... 6,453 53,764 2 76 60,295
----------- ---------- ------------ --------- ---------
Operating segment income (loss)............. 73,828 53,167 (2,777) - 124,218
Write-down of oil and gas properties and
impairments............................... - (14,537) - - (14,537)
Minority interest........................... (9,319) - - - (9,319)
----------- ---------- ------------ --------- ---------
Net income (loss)........................... $ 64,509 $ 38,630 $ (2,777) $ - $ 100,362
=========== ========== ============ ========= =========
Total assets................................ $ 209,733 $ 122,355 $ 52,302 $ (49,198) $ 335,192
=========== ========== ============ ========= =========
Additions to properties..................... $ 42,486 $ 738 $ 122 $ - $ 43,346
=========== ========== ============ ========= =========
S-18
YEAR ENDED DECEMBER 31, 2001:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
----------- ------------- ------------ ------------ ------------
Revenues
Oil sales........................... $122,386sales............................... $ --122,386 $ --- $ -- $122,386
-------- -------- --------- $ - $ 122,386
----------- ---------- ------------ --------- -----------------
Expenses
Operating expenses..................expenses...................... 42,037 55 667 --- 42,759
Depletion, depreciation and
amortization.....................amortization.......................... 22,096 3,408 12 --- 25,516
General and administrative..........administrative.............. 4,151 14,972 949 --- 20,072
Taxes other than on income..........income.............. 4,666 704 -- --- - 5,370
-------- -------- ------------------- ---------- ------------ --------- -----------------
Total expenses...................expenses.................... 72,950 19,139 1,628 --- 93,717
-------- -------- ------------------- ---------- ------------ --------- -----------------
Income (loss) from operations.........operations............... 49,436 (19,139) (1,628) --- 28,669
Other non-operating income (expense):
Investment earnings and other.......other........... 5,995 2,053 60 (5,020) 3,088
Interest expense....................expense........................ (7,403) (22,695) --- 5,223 (24,875)
Net gain on exchange rates..........rates.............. 732 36 -- --- - 768
Intersegment revenues (expenses)............ (14,983) 14,983 -- -- --- - -
Equity in income of affiliated
companies........................ -- --companies............................. - - 5,902 --- 5,902
-------- -------- ------------------- ---------- ------------ --------- -----------------
(15,659) (5,623) 5,962 203 (15,117)
-------- -------- ------------------- ---------- ------------ --------- -----------------
Income (loss) before income taxes.....taxes........... 33,777 (24,762) 4,334 203 13,552
Income tax (benefit) expense..........expense ............... 6,491 (42,392) --- 203 (35,698)
-------- -------- ------------------- ---------- ------------ --------- -----------------
Operating segment income..............income.................... 27,286 17,630 4,334 --- 49,250
Write-down of oil and gas properties and
impairments..................... --impairments............................... - (468) -- --- - (468)
Minority interest.....................interest........................... (5,545) -- -- --- - - (5,545)
-------- -------- ------------------- ---------- ------------ --------- -----------------
Net income............................income.................................. $ 21,741 $ 17,162 $ 4,334 $ --- $ 43,237
======== ======== =================== ========== ============ ========= =================
Total assets.......................... $167,671 $165,254 $100,801assets................................ $ 167,671 $ 165,254 $ 100,801 $ (85,575) $348,151
======== ======== ========$ 348,151
=========== ========== ============ ========= =================
Additions to properties...............properties..................... $ 43,411 $ --- $ 31 $ --- $ 43,442
======== ======== =================== ========== ============ ========= =================
S-21
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED DECEMBER 31, 2000:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
-------------------- ------------- -------- ------------ ------------ (IN THOUSANDS)------------
YEAR ENDED DECEMBER 31, 2000:
Revenues
Oil and natural gas sales........... $139,890sales............... $ 139,890 $ 394 $ --- $ -- $140,284
-------- -------- --------- $ 140,284
----------- ---------- ------------ --------- -----------------
139,890 394 -- --- - 140,284
-------- -------- ------------------- ---------- ------------ --------- -----------------
Expenses
Operating expenses..................expenses...................... 46,727 59 644 --- 47,430
Depletion, depreciation and
amortization.....................amortization.......................... 16,285 879 11 --- 17,175
General and administrative..........administrative.............. 3,659 12,014 1,066 --- 16,739
Taxes other than on income..........income.............. 3,355 1,048 (13) --- 4,390
-------- -------- ------------------- ---------- ------------- --------- -----------------
Total expenses...................expenses.................... 70,026 14,000 1,708 --- 85,734
-------- -------- ------------------- ---------- ------------ --------- -----------------
Income (loss) from operations.........operations............... 69,864 (13,606) (1,708) --- 54,550
Other non-operating income (expense):
Investment earnings and other.......other........... 1,392 8,986 --- (1,819) 8,559
Interest expense....................expense........................ (6,131) (24,661) --- 1,819 (28,973)
Net gain on exchange rates..........rates.............. 298 28 -- --- - 326
Intersegment revenues (expenses)............ (12,226) 12,226 -- -- --- - -
Equity in income of affiliated
companies........................ -- --companies............................. - - 5,313 --- 5,313
-------- -------- ------------------- ---------- ------------ --------- -----------------
(16,667) (3,421) 5,313 --- (14,775)
-------- -------- -------------------- ----------- ------------ --------- -----------------
Income (loss) before income taxes.....taxes........... 53,197 (17,027) 3,605 --- 39,775
Income tax expense....................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..................... --impairments............................... - (1,346) -- --- - (1,346)
Minority interest.....................interest........................... (7,869) -- -- --- - - (7,869)
Extraordinary income on debt repurchase.......................... --repurchase..... - 3,960 -- --- - 3,960
-------- -------- ------------------- ---------- ------------ --------- -----------------
Net income (loss)................................................ $ 31,308 $(14,425)$ (14,425) $ 3,605 $ --- $ 20,488
======== ======== =================== ========== ============ ========= =================
Total assets.......................... $166,462 $156,780assets................................ $ 166,462 $ 156,780 $ 78,406 $(115,201) $286,447
======== ======== ========$ 286,447
=========== ========== ============ ========= =================
Additions to properties...............properties..................... $ 54,112 $ 3,075 $ 9 $ --- $ 57,196
======== ======== =================== ========== ============ ========= ========
S-22
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
--------- ------------- -------- ------------ ------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1999:
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
======== ======== ======== ========= ========
Additions to properties............... $ 25,367 $ 11,579 $ 38 $ -- $ 36,984
======== ======== ======== ========= ========
NOTE 9 --- RUSSIAN OPERATIONS
GEOILBENT LTD.
We own 34 percent of Geoilbent, a Russian limited liability company
formed in 1991 to develop, produce and market crude oil from the North
Gubkinskoye and South Tarasovskoye fields in the West Siberia region of Russia.
Our investment in Geoilbent is accounted for using the equity method. Sales
quantities attributable to Geoilbent for the years ended December 31,September 30, 2002,
2001 and 2000 were 6.9 million Bbls, (4.6 million domestic and 1999
were 5,184,7452.3 million
export) 5.2 million Bbls, 4,247,590 Bbls(0.8 million domestic and 4,267,6474.4 million export) and 4.2
million Bbls, respectively.
S-19
Prices for crude oil for the years ended December 31,September 30, 2002, 2001 and 2000
averaged $13.25 ($8.89 domestic and 1999 averaged$21.73 export), $19.51 $18.54($13.69 domestic and
$8.53$20.48 export) and $18.56 per barrel, respectively. Depletion expense
attributable to Geoilbent for the years ended December 31,September 30, 2002, 2001 and 2000
was $3.93, $2.88 and 1999 was $2.13, $2.29
and $2.27$2.25 per barrel, respectively.
S-23
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Summarized financial
information for Geoilbent follows (in thousands). All amounts represent 100
percent of Geoilbent.
Year ended September 30: 2002 2001 2000
1999
-------- -------- ------------------- ----------- -----------
YEAR ENDED SEPTEMBER 30:
Revenues
Oil sales.......................................... $101,159sales.................................................... $ 78,73591,598 $ 36,424
-------- -------- --------101,159 $ 78,805
----------- ----------- -----------
Expenses
Selling and distribution expenses.................. 9,875expenses............................ 6,696 9,876 4,612
3,654
Operating expenses................................. 11,256 9,798 4,364expenses........................................... 15,360 11,415 8,959
Depletion, depreciation and amortization...........amortization..................... 27,168 14,918 9,557 9,6699,556
General and administrative.........................administrative................................... 8,335 5,650 3,407 2,655
Taxes other than on income.........................income................................... 27,657 26,011 18,286
8,208
-------- -------- --------
67,710 45,660 28,550
-------- -------- ------------------- ----------- -----------
85,216 67,870 44,820
----------- ----------- -----------
Income from operations............................... 33,449 33,075 7,874operations........................................... 6,382 33,289 33,985
Other non-operating income (expense)
Investment earnings and other...................... 649 53 1,375other................................ 381 648 (724)
Interest expense................................... (7,548) (8,145) (3,572)expense............................................. (4,629) (7,547) (7,438)
Net gain (loss) on exchange rates..................rates............................ 2,053 781 (596) 5,152
-------- -------- --------(597)
----------- ----------- -----------
(2,195) (6,118) (8,688) 2,955
-------- -------- --------(8,759)
----------- ----------- -----------
Income before income taxes........................... 27,331 24,387 10,829taxes....................................... 4,187 27,171 25,226
Income tax expense................................... 6,754expense............................................... 302 6,751 6,321
1,333
-------- -------- ------------------- ----------- -----------
Net income...........................................income ...................................................... $ 20,5773,885 $ 18,06620,420 $ 9,496
======== ======== ========18,905
=========== =========== ===========
AT SEPTEMBER 30:
Current assets.......................................assets................................................... $ 34,69618,785 $ 30,07035,447 $ 25,69930,979
Other assets......................................... 187,593 163,219 139,488assets..................................................... 186,815 187,706 163,332
Current liabilities..................................liabilities.............................................. 54,051 60,439 32,700 10,27636,567
Other liabilities....................................liabilities................................................ 7,500 22,550 41,866 54,25438,000
Net equity........................................... 139,300 118,723 100,657equity....................................................... 144,049 140,164 119,744
The European Bank for Reconstruction and Development ("EBRD") and
International Moscow Bank ("IMB") together have agreed in 1996 to lend up to $65
million to Geoilbent, based on achieving certain reserve and production
milestones, under parallel reserve-based loan agreements. As of September 30,
2002, the outstanding balance of the loan with EBRD was $22 million and the IMB
portion was $0.6 million which was repaid in November 2002. By agreement dated
September 23, 2002, the loan agreement with EBRD was restructured into a
revolving credit agreement, with up to $50.0 million available, including the
$22 million already outstanding. The interest rate for the restructured loan is
six-month LIBOR plus 4.75 percent, with additional interest up to 3 percent
during the term portion of the loan based upon Geoilbent's net income. Principal
payments are due in six equal semiannual installments beginning January 27,
2004. The restructured loan agreement grants EBRD a security interest in the
assets of Geoilbent and requires that Geoilbent meet certain financial ratios
and covenants, including a minimum current ratio. As of September 30, 2002,
Geoilbent was not in compliance with the current 1:1 ratio requirement, but had
received a waiver from EBRD through the quarters ended September 30, 2002. The
loan agreement also provides for certain limitations on liens, additional
indebtedness, certain investments, capital expenditures, dividends, mergers and
sales of assets. In addition, the Company and Minley, have pledged their
ownership interests in Geoilbent as security for the debt, and agreed to support
Geoilbent in its obligations under the loan agreement, including providing
technical and managerial personnel and resources to develop its fields. Under
these loan agreements, wethe Company and other shareholders of Geoilbent have significant management and business
support obligations. Each shareholder isMinley are each 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 shareholderthe other of its support
obligations. The loans bear an average interest rate of 15 percent
payable on January 27 and July 27 each year. Principal paymentsAs available, proceeds from the restructured loan will be dueused to
reduce payables and to develop the South Tarasovskoye Field.
S-20
The waiver from EBRD of the current ratio requirement expires March 31,
2003. On March 12, 2003 Geoilbent drew $8.0 million under the loan to reduce
payables, there can be no assurance that the draw will be adequate to permit
Geoilbent to meet the ratio requirement. If Geoilbent fails to meet the ratio
requirements for two consecutive quarters it will result in varying installments onan event of default
whereby EBRD may, at its option, demand payment of the semiannual interest payment dates beginning January
27, 2001outstanding principal and
ending by July 27, 2004. Theinterest. In addition, the restructured loan agreements requireagreement requires that Geoilbent
meet certain financial ratiosimplement a new management information system by May 1, 2003. Geoilbent will be
unable to timely satisfy this requirement which also results in an event of
default whereby EBRD may, at its option, demand payment of the outstanding
principal and covenants, including a minimuminterest.
At September 30, 2002, and September 30, 2001, the current ratio,liabilities
of Geoilbent exceeded its current assets by $35.3 million and provides for certain limitations on liens, additional indebtedness, certain
investment and capital expenditures, dividends, mergers and sales of assets. As$25.7 million,
respectively. Included in current liabilities as of September 30, 2001,2002 are loans
repayable to EBRD ($22.0 million) and IMB ($0.6 million). This debt has been
classified as current because Geoilbent waswill not be able to implement a new
management information system as required by the EBRD loan facility. As a result
of this situation, Geoilbent's independent accountants have indicated in compliancetheir
report that substantial doubt exists regarding Geoilbent's ability to meet its
debts as they come due. While no assurance can be given, the Company believes
these covenant defaults are temporary and does not result in an other than
temporary decline in the Company's investment in Geoilbent or will cause EBRD to
declare a default after considering Geoilbent's historical net income, cash flow
from operating activities and other matters.
Because of Geoilbent's significant working capital deficit, a
substantial portion of its cash flow must be utilized to reduce accounts and
taxes payable. Additionally, in order to maintain or increase proved oil and gas
reserves, Geoilbent must make substantial capital expenditures in 2003.
Geoilbent's net cash provided by operating activities is dependent on the level
of oil prices, which are historically volatile and are significantly impacted by
the proportion of production that Geoilbent can sell on the export market.
Historically, Geoilbent has supplemented its cash flow from operations with
additional borrowings or equity capital and may need to continue to do so.
Should oil prices decline for a prolonged period or should Geoilbent not have
access to additional capital, Geoilbent would need to reduce its capital
expenditures, which could limit its ability to maintain or increase production
and, in turn, meet its debt service requirements. Asset sales and financing are
restricted under the current ratio
covenant, but received a waiver from EBRD. Geoilbent began borrowing under these
facilities in October 1997 and had borrowed a total of $48.5 million and repaid
$10.0 million through September 30, 2001. The proceeds from the loans were used
by Geoilbent to develop the North Gubkinskoye Field in West Siberia, Russia. The
principal payment
S-24
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
requirements for the long-term debt of Geoilbent at September 30, 2001 are as
follows for the years ending September 30 (in thousands):
2002........................................................ $16,000
2003........................................................ 11,000
2004........................................................ 11,550
-------
$38,550
=======
During 1996 and 1997, we incurred $4.1 million in financing costs related
to the establishmentterms of the EBRD financing which are recorded in other assetsloan.
Geoilbent management plans to further address the working capital
deficit by reducing certain capital expenditures and are subject to amortization over the lifefunding its 2003 debt
service and planned capital expenditures with cash flows from existing producing
properties and its development drilling program. At December 31, 2002, Geoilbent
had accounts payable outstanding of the facility. Geoilbent
reimbursed $2.6 million of such costs in 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. In conjunction with Geoilbent's reserve-based loan agreements with
the EBRD and IMB, repayment of the credit facility was subordinated to payments
due to the EBRD and IMB and, accordingly, the credit facility was reclassified
from current to long-term in 1998. In May 2001, Geoilbent entered into an
agreement with IMB to borrow $3.3 million to repay the Morgan credit facility
and, as a result, our cash collateral was returned. The loan from IMB is due on
November 15, 2002, bears interest at LIBOR plus 6 percent and requires quarterly
payments of principal and interest of approximately $0.6 million beginning in
August 2001.
Excise, pipeline and other tariffs and taxes continue to be levied on all
oil producers and certain exporters, including an oil export tariff that
decreased to $8.00 per ton (approximately $1.10 per barrel) from 23.4 Euros per
ton (approximately $2.85 per barrel). We are unable to predict the impact of
taxes, duties and other burdens for the future for our Russian operations.
Geoilbent has reduced its 2002 capital budget to approximately $16.6$12.2 million of which $2.7approximately $5.9
million is for the North Gubkinskoye Field, $9.7 million
is for the South Tarakovskoye Field, $2.2 million is to carry out seismic and
related exploration activity and $2.0 million is for natural gas plant economic,
technical and feasibility studies. Geoilbent's 2002 operating budget includes
$16 million for principal payments on the loan facility. In addition, Geoilbent
hadwas 90 days or more past due. The amounts outstanding accounts payable of $26.6 million as of December 31, 2001,were primarily to
contractors and vendors for drilling and construction services. Although Geoilbent's reduced capital expenditure budget may help to
alleviate any shortfall of funds available to make payments to the banks and its
creditors as those payments come due, it is uncertain that Geoilbent's cash flow
from operations will be sufficient to do so, and it may be necessary for
Geoilbent to obtain capital contributions from its partners, including the
Company, to have sufficient funds to make these payments on a timely basis.
Although the Company may consider making such a capital contribution, there can
be no assurances that the Company will do so, nor can there be any assurances
that Geoilbent's other partner will be willing or able to do so. Under Russian
law, a creditorcreditors, to whom payments are 90 days or more past due, can force a
company into involuntary bankruptcybankruptcy. Geoilbent's financial statements do not
include any adjustments that might result if Geoilbent were unable to continue
as a going concern.
As of September 30, 2002, the company's
paymentsGeoilbent ($2.5 million from Harvest and
$5.0 million from Minley) shareholders had provided Geoilbent with subordinated
loans totaling $7.5 million. These loans are unsecured and repayable commencing
in January 2004. Our interest rate is based on LIBOR up to January 2004, and
rises from 8 to 12 percent thereafter. There can be no assurance that Geoilbent
will have been due for more than 90 days.the ability to repay the loan made by the Company when due.
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 or arranging for a credit facility of up to $100
million for the project, the terms and timing of which were finalized in
February 2002. Pursuant
to the Cooperation Agreement, we have
S-25
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)We 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, 2001, we had loaned $28.5 million to Arctic
Gas pursuant to an interim credit facility, with interest at LIBOR plus 3
percent, and had earned the right to remove restrictions from shares
representing an approximate 11 percent equity interest. From December 1998 through SeptemberDecember 31,
2001, we purchased shares representing an additional 28 percent equity interest
not subject to any sale or transfer restrictions. We
owned a total ofOn April 12, 2002, we
concluded the Arctic Gas
S-21
Sale and transferred our 68 percent ofequity interest to the outstanding voting sharesbuyer. The equity
earnings of Arctic Gas ashave historically been based on a calendar year ended
September 30. The fourth quarter of December 31, 2001, the first quarter of which approximately 39 percent were not subject to any
restrictions2002 and represent our equity interest.the
first twelve days of April have been included in the results for 2002.
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 weighted-average equity interest, not subject to any
sale or transfer restrictions for the years ended December 31, 2002, 2001 and
2000 and 1999 was 49 percent, 39 percent 29 percent and 2429 percent, respectively. We recorded as our
share in the losses of Arctic Gas $1.5 million, $1.1 million $0.7 million and $0.4$0.7 million
for the yearsperiod ended April 12, 2002 and September 30, 2001, 2000 and 1999,2000,
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: 2002 2001 2000
1999
------- ------- ---------------- ---------- ----------
YEAR ENDED SEPTEMBER 30:
Revenues
Oil Sales............................................. $13,374Sales................................. $ 7,880 $ 13,374 $ 3,354
$ --
------- ------- ---------------- ---------- ----------
Expenses
Selling and distribution expenses.....................expenses......... 3,170 3,867 -- ---
Operating expense.....................................expense......................... 2,473 3,483 1,004 --
Depletion, depreciation and amortization..............amortization.. 333 1,032 432
85
General and administrative............................administrative................ 2,112 3,025 2,154 2,941
Taxes other than on income............................income................ 1,261 3,881 1,422
64
------- ------- ---------------- ---------- ----------
9,349 15,288 5,012
3,090
------- ------- ---------------- ---------- ----------
Loss from operations....................................operations......................... (1,469) (1,914) (1,658) (3,090)
Other non-operating income (expense)
Other income (expense).................................................... (4) 54 (14) 585
Interest and foreign exchange expense.................expense..... (1,722) (1,848) (1,558)
(868)
------- ------- ---------------- ---------- ----------
(1,726) (1,794) (1,572)
(283)
------- ------- ---------------- ---------- ----------
Loss before income taxes................................taxes..................... (3,195) (3,708) (3,230)
(3,373)
Income tax expense...................................... --expense........................... - - 188
--
------- ------- ---------------- ---------- ----------
Net loss................................................ $(3,708) $(3,418) $(3,373)
======= ======= =======loss..................................... $ (3,195) $ (3,708) $ (3,418)
========= ========== ==========
S-26
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
AT SEPTEMBER 30: 2001 2000
1999
-------- -------- ------------------ ----------
AT SEPTEMBER 30:
Current assets.......................................assets............................... $ 4,423 $ 1,205
$ 1,513
Other assets.........................................assets................................. 14,986 10,120
5,043
Current liabilities..................................liabilities.......................... 35,658 23,955
18,068
Net (deficit)........................................................................ (16,249) (12,630) (11,512)
S-22
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, PDVSA.
The operating service agreement covers the Uracoa, Bombal and Tucupita Fields
that comprise the South Monagas Unit.Unit . Under the terms of the operating service
agreement, Benton-Vinccler, a Venezuelan corporation owned 80 percent by us and
20 percent by Vinccler, is a contractor for PDVSA and is responsible for overall
operations of the South Monagas Unit, including all necessary investments to
reactivate and develop the fields comprising the South Monagas 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.
On September 19, 2002, Benton-Vinccler and PDVSA signed an amendment to the
operating service agreement, providing for the delivery of up to 198 Bcf of
natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales are
expected to commence at a rate of 40 to 50 MMcf of natural gas per day in the
fourth quarter of 2003 and gradually increase up to 70 MMcfpd in 12 to 18 months
from the initial sale. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5
million barrels of oil at $7.00 per barrel beginning with our first gas sale.
Initial gas production will come from Uracoa, which allows us to more
efficiently manage the reservoir and eliminate the restrictions on producing oil
wells with high gas to oil ratios. The gas reserves in Bombal will be used to
meet the future terms of the gas contract in 2005 or 2006.
The Venezuelan government maintains full ownership of all hydrocarbons in the
fields.
In December 1999, we entered into agreements with SchlumbergerWe drilled eleven oil 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 Unit. As part of Schlumberger's commitment to the
program, it provides additional technical and engineering resources on-site
full-time in Venezuela. As of December 31, 2000, 26 new oil wells and 2 re-entry
oil wells have been drilled under the alliance program.
In January 2001, we suspended the development drilling program until the
second half of 2001 in order to thoroughly review all aspects of operations in
order to integrate field performance to date with revised computer simulation
modeling and improved well completion technology. In August 2001, drilling re-
commenced in the Uracoa Field under the alliance agreement with Schlumberger. As
of December 31, 2001, we drilled 8 newtwo water injection wells in Uracoa and we identified 7 well
locations in undepleted portions of the Tucupita Field, each of the first two
wells is producing at a sustainable rate of 2,000 Bbls of oil per day as of
March 15, 2002.
In August 2001, Benton-Vinccler signed an agreement to amend the
alliance with Schlumberger. The amended long-term incentive-based alliance
continues to provide incentives intended to improve initial production rates of
new wells and to increase the average life of the downhole pumps at South
Monagas Unit. In addition, Schlumberger has agreed to provide drilling and
completion services for new wells utilizing fixed lump-sum pricing. We chose not
to renew the alliance with Helmerich & Payne and have entered into a standard
drilling contract with Flint South America, Inc. In September 2001, we completed
the majority of the reservoir simulation study of the Uracoa Field and expect to
complete a revised field development plan, incorporating the results of this
study in 2002.
In January 1996, we and our bidding partners, predecessor companies
acquired over time by Burlington Resources, Inc. ("Burlington") and Anadarko
Petroleum Corporation ("Anadarko"), were awarded the right to explore and
develop the Delta Centro Block in Venezuela. The contract required a minimum
exploration work program consisting of a seismic survey and the drilling of
three wells within five years. At the time the
S-27
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.NOTE 11 - UNITED STATES OPERATIONS
We had a 30 percent interest in the exploration venture, with Burlington and Anadarko
each owning a 35 percent interest. In July 1996, formal agreements were
finalized and executed, and we posted an $18 million standby letter of credit,
collateralized in full by a time deposit, to secure our 30 percent share of the
minimum exploration work program. During 1999, the Block's first exploration
well, the Jarina 1-X, penetrated a thick potential reservoir sequence, but
encountered no hydrocarbons. In January 2001, we and our bidding partners
reached an agreement with Corporacion Venezolana del Petroleo, S.A. to terminate
the contract in exchange for the unused portion of the standby letter of credit
of $7.7 million. As a result, we included $7.7 million of restricted cash that
collateralized the letter of credit in the Venezuelan full cost pool. As of
December 31, 2001, our share of expenditures to date on the Delta Centro Block
was $23.1 million.
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 AcadiaLakeside Exploration Prospect,
Cameron Parish, Louisiana. The acquisition included a 15 percent
workingIn September 2002, we determined that the Claude
Boudreaux #1 exploratory well was not prospective for hydrocarbons and assigned
our entire 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.
The agreement with Coastline was terminated on August 31, 2001. However, certain
ongoing operations related to the Lakeside Exploration Prospect are conducted by
Coastline onto a continuing basis.
In March 1997, wethird party. We
recognized $1.1 million impairment in the three months ended September 30, 2002.
We acquired a 40100 percent participation interest in three California State offshore oil and
natural gas leases ("California Leases") and a parcel of onshore property 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 offLLC. We impaired all of the capitalized costs associated with
the California Leases of $9.2 million and the joint interest receivable of $3.1
million due from Molino Energy at December 31, 1999. However, we continue to
evaluateThe Company has determined
that it will not pursue further development of the prospect for potential future drilling activities.
S-28
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)California Leases, and will
plug and abandon the previously drilled exploratory well, and undertake any
required lease and land reclamation. It is believed that these costs will not be
material.
NOTE 12 --- CHINA OPERATIONS
In December 1996, we acquired Crestone Energy Corporation, subsequently renamed
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 primaryCompany. Its principal asset is a large undeveloped acreage position in the South China Sea under 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 1.25 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 forand Vietnam. Vietnam has executed 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 sovereigntyagreement on a
portion of the contractsame offshore acreage with another company. The territorial
dispute has lasted for many years, and there has been limited exploration and no
development activity in the area it is unclear when such
program will commence.under dispute. As part of our review of company
assets, we conducted a third-party evaluation of the WAB-21 area. Through that
evaluation and our own assessment we recorded a $13.4 million impairment charge
in the second quarter of 2002. WAB-21 represents the $2.9 million excluded from
the full cost pool as reflected on our December 31, 2002 balance sheet.
S-23
NOTE 13 --- RELATED PARTY TRANSACTIONS
From 1996 through 1998, we made unsecured loans to our then Chief Executive
Officer, A.E.A. E. Benton, bearing interest at the rate of 6 percent per annum. We
subsequently obtained a security interest in Mr. Benton's shares of our stock
and stock options. In August 1999, Mr. Benton filed a Chapterchapter 11
(reorganization) bankruptcy petition in the U.S. Bankruptcy Court for the
Central District of California, in Santa Barbara, California. 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 contractorunder a consulting agreement to perform certain services for
us. During 2001, weIn addition, the consulting agreement provided Mr. Benton with incentive
bonuses tied to our net cash receipts from the sale of our interests in Arctic
Gas and Geoilbent. We paid Mr. Benton $116,833, and have paid a total of $536,545 from February 2000
through May 11, 2001 for services performed under the consulting agreement.agreement, and in
June 2002, we made an estimated incentive bonus payment to Mr. Benton of $1.5
million in connection with the Arctic Gas Sale which we recorded as a reduction
of the gain on the Arctic Gas Sale.
On May 11, 2001, Mr. Benton and the Company entered into a settlement and
release agreement under which the consulting agreement was terminated as to
future services and Mr. Benton agreed to propose a plan of reorganization in his
bankruptcy case that provides for the repayment of our loans to him. We
currently continueIn March
2002, Mr. Benton filed a plan of reorganization in his bankruptcy case which
incorporated the terms of the settlement agreement. On July 31, 2002, the
bankruptcy court confirmed the plan of reorganization, and the order to retainbecome
final on August 10, 2002. As of that date, Mr. Benton's indebtedness was about
$6.7 million for which we provided a full reserve. On August 14, 2002, we
exercised our security interest in Mr. Benton'srights with respect to 600,000 shares of our stock in the Company
pledged to repayment of the loan and took the shares into the Company as
treasury stock. Based on a $3.56 closing price for the stock on that date, the
value of the shares was $2.1 million. Also, in his stock options, andSeptember 2002, we received a
payment of about $1.1 million as a partial distribution from Mr. Benton's
debtor-in-possession account. Finally, under the terms of the settlement
agreement, we have retained about $0.1 million from the right to vote the
shares owned by him and to direct the exercise of his options. Repayment of our
loansArctic Gas bonus payment
to Mr. Benton may be achieved through Mr. Benton's liquidationfor a total recovery of certain
real and personal property assets and a phased liquidation of stock resulting in
Mr. Benton's exercise of his stock options. 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. The amount of Mr. Benton's
indebtedness to us is currently approximately $6.5$3.3 million. We continue to accrue
interest atand provide a reserve on the rateremaining amount due. About $960,000
remains in the debtor-in-possession account which Mr. Benton has withheld to
cover expenses and estimated tax liability for the 600,000 shares of 6 percent per annum and record additional
allowancesstock we
acquired from Mr. Benton. We are due the balance of this account as the interest accrues. The consulting agreement provides that if we
closeexpenses
and tax liabilities are finally determined. We also hold the Proposed Arctic Gas Sale, Mr. Benton will be entitledrights to receive two
percent of our net after-tax cash receipts, actually received by us in the U.S.,
resulting from the Proposed Arctic Gas Sale, excluding any repayment of
indebtedness or advances by us to Arctic Gas. The consulting agreement further
provides that under his proposed bankruptcy plan of reorganization, Mr. Benton
will pay five percent of such amounts to us. Based upon information provided by
Mr. Benton's bankruptcy counsel, we anticipate that under the bankruptcy plan of
reorganization that Mr. Benton will propose, we will receive $1.7 million. This
amount does not include the amounts that we will realize fromdirect
the exercise of Mr. Benton's optionsstock options.
Mr. Benton and the subsequent saleCompany disagree over Mr. Benton's remaining obligations to
us under the settlement agreement and plan of reorganization. In addition, Mr.
Benton is claiming that he is due significant additional amounts with respect to
the resulting shares, nor does
it includeincentive bonus associated with the net proceedsArctic Gas Sale. Mr. Benton and the
Company have agreed to submit their dispute to binding arbitration. While the
outcome of arbitration cannot be predicted, we believe that we will receive from the sale of Mr. Benton's
600,000 shares ofhave a
substantial basis for our stock.
In May 2001, we entered into a Termination Agreementpositions and a Consulting
Agreement with our Chairman of the Board, Michael B. Wray. Under the Termination
Agreement, Mr. Wray's employment relationship with us and any of our
subsidiaries and affiliates terminated as of May 7, 2001. As consideration for
entering into the Termination Agreement and settlement of all sums owedintend to Mr.
Wray for his services as director through the 2001 Annual Meeting of
Stockholders or as an employee, we paid Mr. Wray $100,000. Upon execution of the
Termination Agreement, all stock options previously granted to Mr. Wray vested
in their entirety. Additionally, under the terms of the Consulting Agreement,
Mr. Wray received $100,000 and provided consulting services on matters
pertaining to our business and that of our affiliates through December 31, 2001.
S-29
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)vigorously pursue them.
NOTE 14 --- 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. Diluted earnings per share reflect the
potential dilution that occurs if securities or other contracts were exercised
or converted to common stock. It also requires dual presentation of basic and
diluted earnings per share for companies with complex capital structures.
Basic earnings per common share ("EPS") is computed by dividing income available
to common stockholders by the weighted-average number of common shares
outstanding for the period. The weighted average number of common shares
outstanding for computing basic EPS was 34.6 million, 34.0 million 30.7 million and 29.630.7
million for the years ended December 31, 2002, 2001 2000 and 1999,2000, respectively.
Diluted EPS reflects the potential dilution that could occur if securities or
other contracts to issue common stock were exercised or converted into common
stock. The weighted average number of common shares outstanding for computing
diluted EPS, including dilutive stock options, was 36.1 million, 34.0 million
30.9 million
and 29.630.9 million for the years ended December 31, 2002, 2001 2000 and 1999,2000,
respectively.
An aggregate of 6.73.5 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, 2001.2002. For the years ended December 31,
2001 and 2000, and 1999, 5.66.7 million and 6.25.6 million options and warrants, respectively,
were excluded from the earnings per share calculations because they were
anti-dilutive.
NOTE 15 -- REDUCTION IN FORCE AND CORPORATE RESTRUCTURING
For 2001, we recorded non-recurring items- SUBSEQUENT EVENT
Benton-Vinccler has hedged a portion of $11.4 million, $5.7 millionits 2003 oil sales by purchasing a WTI
crude oil "put" to protect its 2003 cash flow. The put is for 10,000 barrels of
which are included in general and administrative expenses, $1.7 million of which
are included in depletion, depreciation and amortization, $3.2 million in
operating expenses and $0.8 in taxes other than income. The general and
administrative expenses include $2.2 million on the failed debt exchange, $2.2
million for severance and termination benefits for 33 employees, $1.1 million
for lease relinquishment expenses, and $0.2 million for relocation costs to
Houston. Depletion, depreciation and amortization included $0.9 millionoil per day for the reduction in the carrying valueperiod of fixed assets that were not transferred to
Houston and $0.8 million loss on subleasing the former Carpinteria headquarters.
All expenses were paid or accrued byMarch 1, 2003 through December 31, 2001.2003. Due to
the pricing structure for our Venezuela oil, the put has the economic effect of
hedging approximately 20,000 Bopd. The accrued balanceput costing $2.50 per barrel, or
approximately $7.7 million, has a strike price of $0.1 million will be paid in 2002.
NOTE 16 -- SUBSEQUENT EVENT -- SALE OF ARCTIC GAS COMPANY
On February 27, 2002, we entered into a Sale and Purchase Agreement
("Transaction") to sell our 68 percent interest in Arctic Gas Company to a
nominee of the Yukos Oil Company for $190 million plus approximately $30 million
as repayment of intercompany loans owed to us by Arctic Gas. We intend to retire
all of our $108 million outstanding 11 5/8 percent senior notes in accordance
with their terms, which alone eliminates a substantial interest burden and
removes a near-term concern regarding the Company's liquidity. The remaining net
proceeds and cash received from the repayment of loans will be used to further
reduce debt from time to time, accelerate strategic growth of our remaining
assets in Venezuela and Russia, and for general corporate purposes. On March 22,
2002, we were notified that the Transaction had received the requisite consents
from the Russian Ministry for Antimonopoly Policy and Support for
Entrepreneurship. On March 28, 2002, we received the first payment ($120.0
million) of the Proposed Arctic Gas Sale proceeds. We expect that all aspects of
the Transaction will be completed by April 2002. However, in the event we do not
close the Transaction, we will be required to review additional strategic
alternatives to repay the $108 million of 11 5/8 percent senior notes due May
2003.
S-30$30.00 per barrel.
S-24
BENTON OIL AND GAS COMPANYHARVEST NATURAL RESOURCES, INC. 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)(amounts in thousands, except per share data)
YEAR ENDED DECEMBER 31, 2002
Revenues......................................... $ 27,247 $ 33,022 $ 38,841 $ 27,621
Expenses......................................... (18,720) (35,747) (17,914) (19,765)
Non-operating income (expense)................... (3,948) 142,940 (818) (2,948)
Income (loss) from consolidated companies before
income taxes and minority interests........... 4,579 140,215 20,109 4,908
Income tax expense (benefit)..................... 1,801 59,692 6,612 (7,810)
----------- ----------- ----------- -----------
Income (loss) before minority interests.......... 2,778 80,523 13,497 12,718
Minority interests............................ 1,380 2,031 2,590 3,318
----------- ----------- ----------- -----------
Income (loss) from consolidated companies........ 1,398 78,492 10,907 9,400
Equity in earnings (loss) of affiliated
companies...................................... 87 (2,172) 1,209 1,041
Net income (loss)................................ $ 1,485 $ 76,320 $ 12,116 $ 10,441
Other comprehensive loss......................... -- -- (658) --
----------- ----------- ----------- -----------
Total comprehensive income....................... $ 1,485 $ 76,320 $ 11,458 $ 9,791
=========== =========== =========== ===========
Net income (loss) per common share:
Basic ........................................ $ 0.04 $ 2.20 $ 0.35 $ 0.30
=========== =========== =========== ===========
Diluted....................................... $ 0.04 $ 2.10 $ 0.33 $ 0.28
=========== =========== =========== ===========
QUARTER ENDED
---------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
----------- ----------- ------------ -----------
(amounts in thousands, except per share data)
YEAR ENDED DECEMBER 31, 2001
Revenues...............................Revenues......................................... $ 34,338 $ 32,844 $ 31,370 $ 23,834
Expenses...............................Expenses......................................... (24,674) (24,493) (22,345) (22,673)
Non-operating expense..................expense............................ (5,304) (5,152) (5,119) (5,444)
Income (loss) from consolidated companies before
income taxes and minority interests...................interests........... 4,360 3,199 3,906 (4,283)
Income tax expense (benefit)................................ 3,196 3,881 3,510 (46,285)
-------- -------- -------- ------------------- ----------- ----------- -----------
Income (loss) before minority interests............................interests.......... 1,164 (682) 396 42,002
Minority interests.....................interests............................ 1,293 1,541 1,523 1,188
-------- -------- -------- ------------------- ----------- ----------- -----------
Income (loss) from consolidated companies............................companies........ (129) (2,223) (1,127) 40,814
Equity in earnings (loss) of affiliated
companies............................companies...................................... 2,414 1,061 2,859 (432)
-------- -------- -------- --------
Net income (loss)...................................................... $ 2,285 $ (1,162) $ 1,732 $ 40,382
======== ======== ======== =================== =========== =========== ===========
Net income (loss) per common share:
Basic and Diluted.................Diluted............................. $ 0.07 $ 0.07(0.03) $ (0.03)0.05 $ 0.05 $ 1.19
=========== =========== =========== ===========
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 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 and Diluted................. $ 0.10 $ (0.01) $ 0.29 $ 0.26
S-31In the second quarter of 2002, we recognized in non-operating income, the $140.2
million pre-tax gain on the Arctic Gas Sale, and in expense, the write-down of
capitalized costs of $13.4 million associated with our WAB-21 offshore China
concession.
In the fourth quarter of 2001, we recognized a $50.4 million tax benefit related
to the expected utilization by the Arctic Gas Sale in 2002.
S-25
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:- 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
--------- --------------- ------------- -------- ---------- -------
(IN THOUSANDS)---------
YEAR ENDED DECEMBER 31, 2002
Development costs $ 49,163 $ 120 $ 577 $ 49,860
Exploration costs 794 (149) 88 733
--------- --------- --------- ---------
$ 49,957 $ (29) $ 665 $ 50,593
========= ========= ========= =========
YEAR ENDED DECEMBER 31, 2001
Development costs.................... $35,194costs $ 35,194 $ 77 $ 28 $35,299 $13,580 $48,879$ 35,299
Exploration costs....................costs 7,694 --- 909 8,603
8,136 16,739
------- ------ ------ ------- ------- -------
$42,888--------- --------- --------- ---------
$ 42,888 $ 77 $ 937 $43,902 $21,716 $65,618
======= ====== ====== ======= ======= =======$ 43,902
========= ========= ========= =========
YEAR ENDED DECEMBER 31, 2000
Acquisition costs....................costs $ --- $ --- $ 170 $ 170
$ -- $ 170
Development costs....................costs 47,604 -- --- - 47,604
13,887 61,491
Exploration costs....................costs 94 84 2,470 2,648
4,206 6,854
------- ------ ------ ------- ------- -------
$47,698--------- --------- --------- ---------
$ 47,698 $ 84 $2,640 $50,422 $18,093 $68,515
======= ====== ====== ======= ======= =======
YEAR ENDED DECEMBER 31, 1999
Development costs.................... $22,361 $ --2,640 $ 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
======= ====== ====== ======= ======= =======50,422
========= ========= ========= =========
S-32
TABLE II Capitalized costs related to oil and natural gas producing activities:- 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
--------- ----------------- ------------- ---------
---------- ---------
(IN THOUSANDS)
DECEMBER 31, 2002
Proved property costs $ 519,175 $ 26,210 $ 21,030 $ 566,415
Costs excluded from amortization -- 2,900 -- 2,900
Oilfield inventories 7,286 -- -- 7,286
Less accumulated depletion and impairment (386,824) (26,210) (20,764) (433,798)
--------- --------- --------- ---------
$ 139,637 $ 2,900 $ 266 $ 142,803
========= ========= ========= =========
DECEMBER 31, 2001
Proved property costs........costs $ 469,218 $ 12,892 $ 19,813 $ 501,923
$ 91,463 $ 593,386
Costs excluded from amortization.............. --amortization - 16,248 560 16,808
11,549 28,357
Oilfield inventories.........inventories 15,219 -- --- - 15,219 4,532 19,751
Less accumulated depletion and impairment............impairment (361,313) (12,892) (19,544) (393,749)
(32,684) (426,433)
--------- -------- -------- --------- ----------------- ---------
$ 123,124 $ 16,248 $ 829 $ 140,201
$ 74,860 $ 215,061
========= ======== ======== ========= ================= =========
DECEMBER 31, 2000
Proved property costs........costs $ 426,330 $ 12,879 $ 19,362 $ 458,571
$ 85,086 $ 543,657
Costs excluded from amortization.............. --amortization - 16,183 451 16,634
6,536 23,170
Oilfield inventories.........inventories 15,343 -- --- - 15,343 2,705 18,048
Less accumulated depletion and impairment............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
========= ======== ======== ========= ======== =========
S-33S-26
TABLE III Results of operations for oil and natural gas producing activities:- RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS):
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
------------------------------------ ----------
UNITED STATES
VENEZUELA CHINA AND OTHER SUBTOTAL RUSSIA TOTAL
--------- --------- ------------- -------- ---------- --------
(IN THOUSANDS)---------
YEAR ENDED DECEMBER 31, 20012002
Oil sales......................... $122,386sales $ 126,731 $ -- $122,386 $38,410 $160,796$ -- $ 126,731
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income... 42,212 722 42,934 19,934 62,868
Depletion....................... 22,119income 31,608 2,493 -- 22,119 5,367 27,48634,101
Write-down of oil and gas properties
and impairments...impairments -- 468 46813,371 1,166 14,537
Depletion 24,941 -- 468-- 24,941
Income tax expense.............. 11,156 13 11,169 3,238 14,407
-------- -------- -------- ------- --------expense 4,715 3 -- 4,718
--------- --------- --------- ---------
Total expenses............... 75,487 1,203 76,690 28,539 105,229
-------- -------- -------- ------- --------expenses 61,264 15,867 1,166 78,297
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities......................activities $ 46,89965,467 $ (1,203)(15,867) $ 45,696(1,166) $ 9,871 $ 55,567
======== ======== ======== ======= ========48,434
========= ========= ========= =========
YEAR ENDED DECEMBER 31, 20002001
Oil and natural gas sales......... $139,890sales $ 394 $140,284 $26,091 $166,375122,386 $ -- $ -- $ 122,386
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income... 46,879 731 47,610 10,152 57,762
Depletion....................... 15,331 45 15,376 3,305 18,681income 42,212 -- 722 42,934
Write-down of oil and gas properties
and impairments...impairments - 13 455 468
Depletion 22,119 -- 1,346 1,346 -- 1,34622,119
Income tax expense.............. 20,398 12 20,410 3,275 23,685
-------- -------- -------- ------- --------expense 11,156 -- 13 11,169
--------- --------- --------- ---------
Total expenses............... 82,608 2,134 84,742 16,732 101,474
-------- -------- -------- ------- --------expenses 75,487 13 1,190 76,690
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities......................activities $ 57,28246,899 $ (1,740)(13) $ 55,542(1,190) $ 9,359 $ 64,901
======== ======== ======== ======= ========45,696
========= ========= ========= =========
YEAR ENDED DECEMBER 31, 19992000
Oil sales.........................and natural gas sales $ 89,060139,890 $ -- $ 89,060 $11,006 $100,066394 $ 140,284
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income... 38,841 710 39,551 4,139 43,690
Depletion....................... 14,829income 46,879 -- 14,829 3,325 18,154731 47,610
Write-down of oil and gas properties
and impairments...impairments -- 25,891 25,8918 1,338 1,346
Depletion 15,331 -- 25,89145 15,376
Income tax expense.............. 3,812 638 4,450 436 4,886
-------- -------- -------- ------- --------expense 20,398 -- 12 20,410
--------- --------- --------- ---------
Total expenses............... 57,482 27,239 84,721 7,900 92,621
-------- -------- -------- ------- --------expenses 82,608 8 2,126 84,742
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities......................activities $ 31,578 $(27,239)57,282 $ 4,339(8) $ 3,106(1,732) $ 7,445
======== ======== ======== ======= ========55,542
========= ========= ========= =========
Geoilbent (34 percent ownership by us) and Arctic Gas (39 percent, 29
percent and 24 percent ownership not subject to certain sale and transfer
restrictions at December 31, 2001, 2000 and 1999,
S-34
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, 2001, 2000 and 1999.
TABLE IV Quantities of Oil and Natural Gas Reserves- 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. Venezuelan reserves include production
projected through the end of the operating service agreement in July 2012.
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.
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
S-27
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.
The evaluations of the oil and natural gas reserves as of December 31, 2002,
2001 and 2000 were prepared by Ryder Scott Company L.P., independent petroleum
engineers.
The tables shown below represent our interests in the United Sates and Venezuela
in each of the years. In addition to these reserves is our 34 percent interest
in Geoilbent which combined with our United States and Venezuela crude oil,
condensate and natural gas liquids reserves, represent our net interest in all
reserves as of December 31, 2002.
S-28
MINORITY
UNITED INTEREST IN
STATES VENEZUELA VENEZUELA NET TOTAL
--------- --------- ----------- ---------
PROVED RESERVES-CRUDE OIL, CONDENSATE,
AND NATURAL GAS LIQUIDS (MBbls)
YEAR ENDED DECEMBER 31, 2002
Proved reserves beginning of the year.. -- 104,514 (20,903) 83,611
Revisions of previous estimates.... -- 362 (72) 290
Extensions, discoveries and
improved recovery................ -- -- -- --
Production......................... -- (9,708) 1,942 (7,766)
Sales of reserves in place......... -- -- -- --
--------- --------- --------- ---------
Proved reserves at end of the year..... -- 95,168 (19,033) 76,135
========= ========= ========= =========
Russia - Geoilbent (34%) Proved
reserves at end of the year.......... 24,781
=========
YEAR ENDED DECEMBER 31, 2001
Proved reserves beginning of the year.. -- 123,039 (24,608) 98,431
Revisions of previous estimates.... -- (8,747) 1,749 (6,998)
Extensions, discoveries and
improved recovery................ -- -- -- --
Production......................... -- (9,778) 1,956 (7,822)
Sales of reserves in place......... -- -- -- --
--------- --------- --------- ---------
Proved reserves at end of the year..... -- 104,514 (20,903) 83,611
========= ========= ========= =========
Russia - Arctic Gas (39%) Proved
reserves at end of the year.......... 20,964
=========
Russia - Geoilbent (34%) Proved
reserves at end of the year.......... 29,668
=========
YEAR ENDED DECEMBER 31, 2000
Proved reserves at beginning of the
year................................. -- 134,961 (26,992) 107,969
Revisions of previous estimates.... -- (8,826) 1,765 (7,061)
Purchases of reserves in place..... 15 -- -- 15
Extensions, discoveries and
improved recovery................ -- 6,268 (1,254) 5,014
Production......................... (7) (9,364) 1,873 (7,498)
Sales of reserves in place......... (8) -- -- (8)
--------- --------- --------- ---------
Proved reserves at end of the year..... -- 123,039 (24,608) 98,431
========= ========= ========= =========
Russia - Arctic Gas (29%) Proved
reserves at end of the year.......... 15,821
=========
Russia - Geoilbent (34%) Proved
reserves at end of the year.......... 32,614
=========
PROVED DEVELOPED RESERVES AT:
December 31, 2002...................... -- 53,833 (10,767) 43,066
December 31, 2001...................... -- 51,465 (10,293) 41,172
December 31, 2000...................... -- 67,217 (13,443) 53,774
Russia - Arctic Gas Proved reserves
at end of the year
2001 (39%)............................. 2,483
2000 (29%)............................. 2,325
Russia - Geoilbent (34%) Proved
reserves at end of the year
2002................................... 11,840
2001................................... 15,658
2000................................... 14,913
PROVED RESERVES-NATURAL GAS (MMcf)
YEAR ENDED DECEMBER 31, 2002
Proved reserves beginning of the year.. -- -- -- --
Revisions of previous estimates.... -- -- -- --
Extensions, discoveries and
improved recovery................ -- 198,000 (39,600) 158,400
Sales of reserves in place......... -- -- -- --
--------- --------- --------- ---------
Proved reserves end of the year........ 198,000 (39,600) 158,400
========= ========= ========= =========
Russia - Arctic Gas (39%) Proved
reserves - December 31, 2001......... 208,010
=========
Russia - Arctic Gas (39%)
Proved reserves - December 31, 2000.. 152,496
=========
PROVED DEVELOPED RESERVES AT:
December 31, 2002...................... -- 105,000 (21,000) 84,000
Russia - Arctic Gas
2001 (39%)............................. 21,292
2000 (29%)............................. 17,801
S-29
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.
The tables shown below represent our interest Venezuela in each of the years. In
addition to these reserves is our 34 percent interest in Geoilbent and our
Arctic Gas interest of 39% and 29% at December 31, 2001 and 2000, respectively.
Which combined with our Venezuela crude oil, condensate and natural gas liquids
reserves represent our net interest in all reserves as of December 31, 2002.
Geoilbent's Russian domestic crude oil price declined significantly for the
period from September 30, 2002 until December 31, 2002. The standardized measure
of discounted future net cash flows declined from $92.9 million to $41.5
million. There was a $5.05 per barrel decline in the value of a barrel between
these two periods. The reserves in place and development cost structure were
approximately the same. The lower prices at December 31, 2002 were offset by
lower royalties, production taxes, export fees and income taxes. The Russian
domestic crude oil price declined from approximately $9.50 to $5.00 per barrel
by December 31. While world crude oil prices and Russian export prices increased
from approximately $20 to $29. Geoilbent sells approximately 66 percent of its
crude oil sales into the Russian domestic market. Geoilbent's production is
currently limited to shipments on the Transneft crude oil pipeline system. This
system suffers from winter export limitations. Geoilbent reports its
standardized measure of discounted future net cash flows at September 30. The
Company reports the results of Ryder Scott Company L.P. independent engineering
evaluation at December 31 to provide comparability with its Venezuelan reserves.
Geoilbent's 34 percent interest declined by $51.4 million as measured by the
December 31, 2002 year-end weighted average price. We do not believe that the
year-end prices are indicative of the value of Geoilbent. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
MINORITY
INTEREST IN
VENEZUELA VENEZUELA NET TOTAL
----------- ----------- -----------
(amounts in thousands)
DECEMBER 31, 2002
Future cash inflow $ 1,510,346 $ (302,069) $ 1,208,277
Future production costs (400,694) 80,139 (320,555)
Future development costs (192,671) 38,534 (154,137)
----------- ----------- -----------
Future net revenue before income taxes 916,981 (183,396) 733,585
10% annual discount for estimated timing
of cash flows (315,376) 63,075 (252,301)
----------- ----------- -----------
Discounted future net cash flows before
income taxes 601,605 (120,321) 481,284
Future income taxes, discounted at 10%
per annum (204,356) 40,871 (163,485)
----------- ----------- -----------
Standardized measure of discounted future
net cash flows $ 397,249 $ (79,450) $ 317,799
=========== =========== ===========
Russia - Geoilbent (34%) $ 45,395
===========
S-30
DECEMBER 31, 2001
Future cash flows $ 1,030,404 $ (206,081) $ 824,323
Future production costs (558,431) 111,686 (446,745)
Future development costs (142,006) 28,401 (113,605)
----------- ----------- -----------
Future net revenue before income taxes 329,967 (65,994) 263,973
10% annual discount for estimated timing
of cash flows (109,704) 21,941 (87,763)
----------- ----------- -----------
Discounted future net cash flows before
income taxes 220,263 (44,053) 176,210
Future income taxes, discounted at 10%
per annum (16,103) 3,221 (12,882)
----------- ----------- -----------
Standardized measure of discounted future
net cash flows $ 204,160 $ (40,832) $ 163,328
=========== =========== ===========
Russia - Arctic Gas (29%) $ 82,205
===========
Russia - Geoilbent (34%) $ 70,648
===========
DECEMBER 31, 2000
Future cash inflow $ 1,505,870 $ (301,174) $ 1,204,696
Future production costs (618,870) 123,774 (495,096)
Future development costs (166,039) 33,208 (132,831)
----------- ----------- -----------
Future net revenue before income taxes 720,961 (144,192) 576,769
10% annual discount for estimated timing
of cash flows (260,381) 52,076 (208,305)
----------- ----------- -----------
Discounted future net cash flows before
income taxes 460,580 (92,116) 368,464
Future income taxes, discounted at 10%
per annum (104,894) 20,979 (83,915)
----------- ----------- -----------
Standardized measure of discounted future
net cash flows $ 355,686 $ (71,137) $ 284,549
=========== =========== ===========
Russia - Arctic Gas (29%) $ 56,880
===========
Russia - Geoilbent (34%) $ 114,725
===========
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
NET VENEZUELA
-----------------------------------
2002 2001 2000
--------- --------- ---------
(AMOUNTS IN THOUSANDS)
Present Value at January 1 $ 163,328 $ 284,549 $ 380,865
Sales of oil and natural gas, net of related costs (76,098) (64,139) (58,913)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs 310,043 (141,429) (124,402)
Quantities 611 (26,198) (26,494)
Extensions, discoveries and improved recovery, net of future costs 89,670 -- 16,429
Accretion of discount 17,621 36,846 52,135
Net change in income taxes (150,603) 71,033 56,567
Development costs incurred 40,532 23,768 36,210
Changes in timing and other (77,305) (21,102) (47,848)
--------- --------- ---------
Present Value at December 31 $ 317,799 $ 163,328 $ 284,549
========= ========= =========
S-31
ADDITIONAL SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING
ACTIVITIES (UNAUDITED) FOR RUSSIA EQUITY AFFILIATES AS OF SEPTEMBER 30, THEIR
FISCAL YEAR END.
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.
Geoilbent (34 percent ownership by us) and Arctic Gas (39 percent and 29 percent
ownership not subject to certain sale and transfer restrictions at December 31,
2002 and 2001, until Arctic Gas was sold on April 12, 2002, 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, 2002, 2001, and 2000.
TABLE I - TOTAL COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION
AND DEVELOPMENT ACTIVITIES (IN THOUSANDS):
TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------
YEAR ENDED SEPTEMBER 30, 2002
Development costs $ -- $ 8,501 $ 8,501
Exploration costs 16,156 498 16,654
--------- --------- ---------
$ 16,156 $ 8,999 $ 25,155
========= ========= =========
YEAR ENDED SEPTEMBER 30, 2001
Development costs $ -- $ 11,418 $ 11,418
Exploration costs 8,136 2,074 10,210
--------- --------- ---------
$ 8,136 $ 13,492 $ 21,628
========= ========= =========
YEAR ENDED SEPTEMBER 30, 2000
Development costs $ -- $ 13,290 $ 13,290
Exploration costs 4,206 279 4,485
--------- --------- ---------
$ 4,206 $ 13,569 $ 17,775
========= ========= =========
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS):
TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------
SEPTEMBER 30, 2002
Proved property costs $ -- $ 94,404 $ 94,404
Costs excluded from amortization -- 272 272
Oilfield inventories -- 2,348 2,348
Less accumulated depletion and impairment -- (31,440) (31,440)
--------- --------- ---------
$ -- $ 65,584 $ 65,584
========= ========= =========
SEPTEMBER 30, 2001
Proved property costs $ 5,786 $ 85,677 $ 91,463
Costs excluded from amortization 11,549 -- 11,549
Oilfield inventories 175 4,357 4,532
Less accumulated depletion and impairment (389) (22,203) (22,592)
--------- --------- ---------
$ 17,121 $ 67,831 $ 84,952
========= ========= =========
SEPTEMBER 30, 2000
Proved property costs $ 12,901 $ 72,184 $ 85,085
Costs excluded from amortization 6,536 -- 6,536
Oilfield inventories -- 2,705 2,705
Less accumulated depletion and impairment (78) (17,130) (17,208)
--------- --------- ---------
$ 19,359 $ 57,759 $ 77,118
========= ========= =========
S-32
TABLE III - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS):
TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------
YEAR ENDED DECEMBER 31, 2002
Oil sales $ 3,554 $ 31,039 $ 34,593
Expenses:
Operating, selling and distribution expenses and taxes
other than on income 3,102 16,902 20,004
Depletion 139 9,237 9,376
Income tax expense 19 1,955 1,974
--------- --------- ---------
Total expenses 3,260 28,094 31,354
--------- --------- ---------
Results of operations from oil and natural gas
producing activities $ 294 $ 2,945 $ 3,239
========= ========= =========
YEAR ENDED DECEMBER 31, 2001
Oil sales $ 4,016 $ 34,261 $ 38,277
Expenses:
Operating, selling and distribution expenses and taxes
other than on income 3,381 16,083 19,464
Depletion 311 5,072 5,383
Income tax expense 80 3,742 3,822
--------- --------- ---------
Total expenses 3,772 24,897 28,669
--------- --------- ---------
Results of operations from oil and natural gas
producing activities $ 244 $ 9,364 $ 9,608
========= ========= =========
YEAR ENDED DECEMBER 31, 2000
Oil sales $ 889 $ 26,716 $ 27,605
Expenses:
Operating, selling and distribution expenses and taxes
other than on income 604 10,831 11,435
Depletion 78 3,249 3,327
Income tax expense 54 3,306 3,360
--------- --------- ---------
Total expenses 736 17,386 18,122
--------- --------- ---------
Results of operations from oil and natural gas
producing activities $ 153 $ 9,330 $ 9,483
========= ========= =========
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. Geoilbent and Arctic Gas oil and gas fields are situated on land
belonging to the Government of the Russian Federation. Each obtained licenses
from the local authorities and pays unified production taxes to explore and
produce oil and gas from these fields. Geoilbent's licenses will expire in
September 2018 the license expiration for the North Gubkinskoye field, and in
March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the
Russian Federal Law 20-FZ, dated January 2, 2000, the license may be extended
over the economic life of the lease at Geoilbent's option. Geoilbent intends to
extend such licenses for properties that are expected to produce subsequent to
their expiry dates. Estimates of proved reserves extending past the license
expiration represent approximately 5 percent of total proved reserves. Arctic
Gas had licenses to develop the Samburg and Yevo-Yakhinskiy fields in western
Siberia. Arctic Gas was sold on April 12, 2002.
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.
S-33
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.
S-35
The evaluations of the oil and natural gas reserves as of December 31, 2001
and 2000 were prepared by Ryder-Scott, independent petroleum engineers. The
evaluations of the oil and natural gas reserves as of December 31, 1999 were
audited by Huddleston & Co., Inc., independent petroleum engineers.
TOTAL EQUITY
CONSOLIDATED COMPANIESARCTIC GAS GEOILBENT AFFILIATES
-------------------------------------------- ---------- MINORITY
UNITED INTEREST IN
STATES VENEZUELA VENEZUELA NET TOTAL RUSSIA TOTAL
------ --------- ----------- --------- ---------- -------------------
PROVED RESERVES-CRUDE OIL, CONDENSATE,
AND NATURAL GAS LIQUIDS (MBBLS)(MBbls)
YEAR ENDED DECEMBER 31,SEPTEMBER 30, 2002
Proved reserves beginning of the year 20,965 29,668 50,633
Revisions of previous estimates -- (3,455) (3,455)
Extensions, discoveries and improved recovery -- 1,493 1,493
Production (89) (2,350) (2,439)
Sales of reserves in place (20,876) -- (20,876)
--------- --------- ---------
Proved reserves at end of the year -- 25,356 25,356
========= ========= =========
YEAR ENDED SEPTEMBER 30, 2001
Proved reserves beginning of the year... -- 123,039 (24,608) 98,431year 15,821 32,614 48,435 146,866
Revisions of previous estimates...... -- (8,747) 1,749 (6,998) (54) (7,052)estimates 5,327 (5,594) (267)
Extensions, discoveries and improved recovery...........................recovery -- 4,411 4,411
Production (183) (1,763) (1,946)
Sales of reserves in place -- -- --
-- 4,411 4,411
Production........................... -- (9,778) 1,956 (7,822) (2,160) (9,982)
---- ------- ------- ------- ------- ---------------- --------- ---------
Proved reserves at end of year............. -- 104,514 (20,903) 83,611 50,632 134,243
==== ======= ======= ======= ======= =======the year 20,965 29,668 50,633
========= ========= =========
YEAR ENDED DECEMBER 31,SEPTEMBER 30, 2000
Proved reserves beginning of the year... -- 134,961 (26,992) 107,969year 3,715 36,414 40,129 148,098
Revisions of previous estimates...... -- (8,826) 1,765 (7,061)estimates 4,093 (6,904) (2,811) (9,872)
Purchases of reserves in place....... 15 -- -- 15 -- 15
Extensions, discoveries and improved recovery........................... -- 6,268 (1,254) 5,014recovery 8,062 4,548 12,610
17,624
Production........................... (7) (9,364) 1,873 (7,498)Production (49) (1,444) (1,493) (8,991)
Sales of reserves in place........... (8)place -- -- (8) --
(8)
---- ------- ------- ------- ------- ---------------- --------- ---------
Proved reserves at end of year.............the year 15,821 32,614 48,435
========= ========= =========
PROVED DEVELOPED RESERVES AT:
September 30, 2002 -- 123,039 (24,608) 98,431 48,435 146,866
==== ======= ======= ======= ======= =======11,840 11,840
September 30, 2001 2,483 15,658 18,141
September 30, 2000 2,325 14,913 17,238
S-34
PROVED RESERVES-NATURAL GAS (MMcf)
YEAR ENDED DECEMBER 31, 1999SEPTEMBER 30, 2002
Proved reserves beginning of the year...year 208,010 -- 137,835 (27,567) 110,268 31,053 141,321208,010
Revisions of previous estimates......estimates -- (7,488) 1,498 (5,990) (531) (6,521)-- --
Extensions, discoveries and improved recovery...........................recovery -- 14,281 (2,856) 11,425 11,058 22,483
Production........................... -- (9,667) 1,933 (7,734) (1,451) (9,185)
---- ------- ------- ------- ------- ---------
Production -- -- --
Sales of reserves in place (208,010) -- (208,010)
--------- --------- ---------
Proved reserves end of year.............the year -- 134,961 (26,992) 107,969 40,129 148,098
==== ======= ======= ======= ======= =======
PROVED DEVELOPED RESERVES AT:
December 31, 2001....................... -- 51,465 (10,293) 41,172 18,141 59,313
December 31, 2000....................... --
67,217 (13,443) 53,774 17,238 71,012
December 31, 1999....................... -- 67,118 (13,423) 53,695 15,120 68,815
December 31, 1998....................... -- 75,636 (15,127) 60,509 9,745 70,254
PROVED RESERVES-NATURAL GAS (MMCF)========= ========= =========
YEAR ENDED DECEMBER 31,SEPTEMBER 30, 2001
Proved reserves beginning of the year...year 152,496 -- -- -- -- 152,496 152,496
Revisions of previous estimates......estimates 55,514 -- 55,514
Extensions, discoveries and improved recovery -- -- --
Production -- 55,514 55,514
---- ------- ------- ------- ------- --------- --
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves end of the year.........year 208,010 -- 208,010
========= ========= =========
YEAR ENDED SEPTEMBER 30, 2000
Proved reserves beginning of the year -- -- --
Revisions of previous estimates -- 208,010 208,010
==== ======= ======= ======= ======= =======-- --
Extensions, discoveries and improved recovery 152,496 -- 152,496
Production -- -- --
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves end of the year 152,496 -- 152,496
========= ========= =========
PROVED DEVELOPED RESERVES AT:
December 31, 2001.......................September 30, 2002 -- -- --
September 30, 2001 21,292 -- 21,292
21,292
December 31, 2000.......................September 30, 2000 17,801 -- -- -- -- 17,801 17,801
S-36S-35
TABLE V Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil
and Natural Gas Reserve Quantities- 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.
Excise, pipeline and other tariffs and taxes continue to be levied on all
oil producers and certain exporters, including an oil export tariff that
decreased to $8.00 per ton (approximately $1.10 per barrel) from 23.4 Euros per
ton (approximately $2.85 per barrel). We are unable to predict the impact of
taxes, duties and other burdens for the future for our Russian operations.
TOTAL EQUITY
CONSOLIDATED COMPANIESARCTIC GAS GEOILBENT AFFILIATES
------------------------------------- ---------- MINORITY
INTEREST IN
VENEZUELA VENEZUELA NET TOTAL RUSSIA TOTAL
---------- ----------- ---------- ---------- -----------
(AMOUNTS IN THOUSANDS)--------- ------------
(amounts in thousands)
DECEMBER 31, 2001SEPTEMBER 30, 2002
Future cash inflow.............. $1,030,404 $(206,081)inflow $ 824,323 $1,064,688-- $ 1,889,011469,837 $ 469,837
Future production costs......... (558,431) 111,686 (446,745) (624,793) (1,071,538)costs -- 203,754) (203,754)
Future development costs........ (142,006) 28,401 (113,605) (86,159) (199,764)
----------costs -- (40,707) (40,707)
--------- ---------- ------------------- -----------
Future net revenue before income taxes........................ 329,967 (65,994) 263,973 353,736 617,709taxes -- 225,376 225,376
10% annual discount for estimated timing of cash flows........................ (109,704) 21,941 (87,763) (164,211) (251,974)
----------flows -- (108,147 (108,147)
--------- ---------- ------------------- -----------
Discounted future net cash flows before income taxes.......... 220,263 (44,053) 176,210 189,525 365,735taxes -- 117,229 117,229
Future income taxes, discounted at 10% per annum............. (16,103) 3,221 (12,882) (36,672) (49,554)
----------annum -- (24,290) (24,290)
--------- ---------- ------------------- -----------
Standardized measure of discounted future net
cash flows........................flows $ 204,160-- $ (40,832)92,939 $ 163,328 $ 152,853 $ 316,181
==========92,939
========= ========== ========== ===========
S-37
EQUITY
CONSOLIDATED COMPANIES AFFILIATES
------------------------------------- ----------
MINORITY
INTEREST IN
VENEZUELA VENEZUELA NET TOTAL RUSSIA TOTAL
---------- ----------- ---------- ---------- -----------
(AMOUNTS IN THOUSANDS)
DECEMBER 31, 2000========= ===========
SEPTEMBER 30, 2001
Future cash inflow.............. $1,505,870 $(301,174) $1,204,696 $1,273,327inflow $ 2,478,023630,340 $ 434,348 $ 1,064,688
Future production costs......... (618,870) 123,774 (495,096) (811,678) (1,306,774)costs (373,458) (251,335) (624,793)
Future development costs........ (166,039) 33,208 (132,831) (70,620) (203,451)
----------costs (49,139) (37,020) (86,159)
--------- ---------- ------------------- -----------
Future net revenue before income taxes........................ 720,961 (144,192) 576,769 391,029 967,798taxes 207,743 145,993 353,736
10% annual discount for estimated timing of cash flows........................ (260,381) 52,076 (208,305) (176,352) (384,657)
----------flows (99,343) (64,868) (164,211)
--------- ---------- ------------------- -----------
Discounted future net cash flows before income taxes.......... 460,580 (92,116) 368,464 214,677 583,141taxes 108,400 81,125 189,525
Future income taxes, discounted at 10% per annum............. (104,894) 20,979 (83,915) (43,072) (126,987)
----------annum (26,195) (10,477) (36,672)
--------- ---------- ------------------- -----------
Standardized measure of discounted future net
cash flows........................flows $ 355,68682,205 $ (71,137)70,648 $ 284,549 $ 171,605 $ 456,154
==========152,853
========= ========== =================== ===========
DECEMBER 31, 1999SEPTEMBER 30, 2000
Future cash inflow.............. $1,727,228 $(345,446) $1,381,782inflow $ 566,201584,346 $ 1,947,983688,981 $ 1,273,327
Future production costs......... (543,976) 108,795 (435,181) (150,370) (585,551)costs (395,238) (416,440) (811,678)
Future development costs........ (144,639) 28,928 (115,711) (38,210) (153,921)
----------costs (36,585) (34,035) (70,620)
--------- ---------- ------------------- -----------
Future net revenue before income taxes........................ 1,038,613 (207,723) 830,890 377,621 1,208,511taxes 152,523 238,506 391,029
10% annual discount for estimated timing of cash flows........................ (386,930) 77,386 (309,544) (154,032) (463,576)
----------flows (78,006) (98,346) (176,352)
--------- ---------- ------------------- -----------
Discounted future net cash flows before income taxes.......... 651,683 (130,337) 521,346 223,589 744,935taxes 74,517 140,160 214,677
Future income taxes, discounted at 10% per annum............. (175,602) 35,121 (140,481) (47,676) (188,157)
----------annum (17,637) (25,435) (43,072)
--------- ---------- ------------------- -----------
Standardized measure of discounted future net
cash flows........................flows $ 476,08156,880 $ (95,216)114,725 $ 380,865 $ 175,913 $ 556,778
==========171,605
========= ========== =================== ===========
S-38
TABLE VI Changes in the Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserves- CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
CONSOLIDATED COMPANIES EQUITY AFFILIATES
TOTAL
--------------------------------- ------------------------------ --------------------------------------------------------------------
2002 2001 2000 1999 2001 2000 1999 2001 2000 1999
--------- --------- --------- -------- -------- --------
--------- --------- ---------
(AMOUNTS IN THOUSANDS)
Present Value at January 1............October 1 $ 284,549152,853 $ 380,865171,605 $ 49,964 $171,605 $175,913 $ 43,248 $ 456,154 $ 556,778 $ 93,212175,913
Sales of oil and natural gas, net of related costs........ (64,139) (58,913) (40,303)costs (23,644) (19,001) (20,977) (3,238) (83,140) (79,890) (43,541)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs.............. (141,429) (124,402) 552,614costs 76,545 (39,880) (72,740)
120,742 (181,309) (197,142) 673,356
Quantities........... (26,198) (26,494) (26,671)Quantities (10,007) 8,881 (19,685) (2,858) (17,317) (46,179) (29,529)
Sales of reserves in place................ -- -- -- -- -- -- --place (82,205) -- --
Extensions, discoveries and improved recovery, net of future costs......... -- 16,429 65,184costs 2,031 18,767 73,542
54,326 18,767 89,971 119,510
Accretion of discount............. 36,846 52,135 4,996discount 7,065 21,468 22,359 4,955 58,314 74,494 9,951
Net change in income taxes................ 71,033 56,567 (140,481)taxes 1,145 6,400 4,604
(41,378) 77,433 61,171 (181,859)
Development costs incurred............. 23,768 36,210 28,558incurred 8,999 17,110 8,475 4,370 40,878 44,685 32,928
Changes in timing and other................ (21,102) (47,848) (112,996)other (39,843) (32,497) 114 (4,254) (53,599) (47,734) (117,250)
--------- --------- --------- -------- -------- --------
--------- --------- ---------
Present Value at December 31..........September 30 $ 163,32892,939 $ 284,549152,853 $ 380,865 $152,853 $171,605 $175,913 $ 316,181 $ 456,154 $ 556,778
========= ========= ========= ======== ======== ========171,605
========= ========= =========
S-39S-36
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 Houston,
State of Texas, on the 28th day of March, 2002.
BENTON OIL AND GAS COMPANY2003.
HARVEST NATURAL RESOURCES, INC.
(Registrant)
Date: March 28, 2003 By: /s/ PETERPeter J. HILL
------------------------------------Hill
--------------------------------
Peter J. Hill
Chief Executive Officer
Date: March 28, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed by the following persons on the 28th day of March,
2002,2003, on behalf of the Registrant in the capacities indicated:
SIGNATURE TITLESignature Title
- --------- -----
/s/ PETERPeter J. HILLHill Director, President and Chief Executive
Officer
- --------------------------------------------------------------------------------------------------- Officer
Peter J. Hill
/s/ STEVENSteven W. THOLENTholen Senior Vice President, Chief Financial
- --------------------------------------------------- Officer and
- ------------------------------------------------ Treasurer
Steven W. Tholen (Principal Financial Officer)
/s/ KURT A. NELSON Vice President -- Controller
- ------------------------------------------------
Kurt A. Nelson Vice President-Controller
- --------------------------------------------------- (Principal Accounting Officer)
Kurt A. Nelson
/s/ STEPHENStephen D. CHESEBRO'Chesebro' Chairman of the Board and Director
- ---------------------------------------------------------------------------------------------------
Stephen D. Chesebro'
/s/ JOHNJohn U. CLARKEClarke Director
- ---------------------------------------------------------------------------------------------------
John U. Clarke
/s/ BYRON A. DUNNH.H. Hardee Director
- ------------------------------------------------
Byron A. Dunn
/s/ H.H. HARDEE Director
- --------------------------------------------------------------------------------------------------
H.H. Hardee
/s/ PATRICKPatrick M. MURRAYMurray Director
- ---------------------------------------------------------------------------------------------------
Patrick M. Murray
S-40S-37
I, Peter J. Hill, certify that:
1. I have reviewed this annual report on Form 10-K of Harvest Natural
Resources, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: March 28, 2003
/s/ Peter J. Hill
-------------------------------------
Peter J. Hill
President and Chief Executive Officer
S-38
I, Steven W. Tholen, certify that:
1. I have reviewed this annual report on Form 10-K of Harvest Natural
Resources, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: March 28, 2003
/s/ Steven W. Tholen
-------------------------------------
Steven W. Tholen
Senior Vice President and
Chief Financial Officer
S-39
SCHEDULE II
BENTON OIL AND GAS COMPANYHARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTSValuation and Qualifying Accounts
(in thousands)
ADDITIONS
------------------------------------------------------
BALANCE AT CHARGED TO DEDUCTIONS BALANCE AT
BEGINNING OF CHARGED TO OTHER FROM END OF
OF YEAR INCOME ACCOUNTS RESERVES YEAR
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)------------- ------------- ------------- ------------- --------------
AT DECEMBER 31, 2002
Amounts deducted from applicable assets
Accounts receivable $ 6,512 $ 289 $ - $ 3,276 $ 3,525
Deferred tax valuation allowance 19,700 20,577 1,131 39,146
Investment at cost 1,350 - - - 1,350
AT DECEMBER 31, 2001
Amounts deducted from applicable assets
Accounts receivable...................receivable $ 6,518 $ 330 $ --- $ 336 $ 6,512
Valuation allowances..................Deferred tax valuation allowance 54,207 14,352 (11,008) 37,851 19,700
Investment at cost....................cost 1,350 -- -- --- - - 1,350
AT DECEMBER 31, 2000
Amounts deducted from applicable assets
Accounts receivable...................receivable $ 6,187 $ 331 -- --- - $ 6,518
Valuation allowances..................Deferred tax valuation allowance 51,913 2,446 --- 152 54,207
Investment at cost....................cost 1,350 -- -- -- 1,350
AT DECEMBER 31, 1999
Amounts deducted from applicable assets- - - 1,350
S-40
SCHEDULE III
HARVEST NATURAL RESOURCES, INC.
LLC GEOILBENT
FINANCIAL STATEMENTS
30 SEPTEMBER 2002
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Owners of Limited Liability Company Geoilbent
In our opinion, the accompanying balance sheets and the related statements of
income, cash flows and changes in stockholders' equity, present fairly, in all
material respects, the financial position of LLC Geoilbent (the "Company") at 30
September 2002 and 2001, and the results of its operations and its cash flows
for each of the three years in the period ended 30 September 2002, in conformity
with accounting principles generally accepted in the United States of America.
These financial statements are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements 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.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Notes 4 and 11 to the
financial statements, the Company has a long-term debt facility for which it
will be unable to meet certain loan covenants and therefore the lender may
declare the loan to be in default and can accelerate the maturity. Accordingly,
this long-term debt has been classified in the accompanying financial statements
as a current liability resulting in a working capital deficit of approximately
US$ 35,266,000 as at 30 September 2002 which raises substantial doubt about the
Company's ability to continue as a going concern. Management's plans in regards
to this matter are also described in Note 4. The financial statements do not
include any adjustments that might result from the outcome of this uncertainty.
ZAO PricewaterhouseCoopers
Moscow, Russian Federation
28 February 2003
1
LLC GEOILBENT
BALANCE SHEETS
(expressed in thousand of US Dollars)
- ----------------------------------------------------------------------------------------------------------------
As at As at
Notes 30 September 2002 30 September 2001
- ----------------------------------------------------------------------------------------------------------------
ASSETS
Cash and cash equivalents 2,001 4,409
Restricted cash 5 1,469 10,208
Accounts receivable................... $ 3,236 $ 858 2,093 -- $ 6,187
Valuation allowances.................. 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
Bentonreceivable and advances to suppliers 7 6,308 7,265
Inventories 8 7,201 13,565
Deferred income tax, current 15 1,806 -
- ----------------------------------------------------------------------------------------------------------------
TOTAL CURRENT ASSETS 18,785 35,447
Oil and Gas Company stock... 2,093 -- (2,093) -- --gas producing properties, full cost method 9 185,989 186,688
Deferred income tax, non-current 15 696 -
Other long term assets 130 1,018
- ----------------------------------------------------------------------------------------------------------------
TOTAL ASSETS 205,600 223,153
================================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Short-term borrowings 10 - 3,000
Current portion of long-term debt 11 22,550 18,200
Accounts payable 15,244 20,673
Trade advances 3,000 8,753
Taxes payable 12 12,354 7,484
Other payables and accrued expenses 903 2,329
- ----------------------------------------------------------------------------------------------------------------
TOTAL CURRENT LIABILITIES 54,051 60,439
Long-term debt 11 7,500 22,550
- ----------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES 61,551 82,989
================================================================================================================
COMMITMENTS AND CONTINGENT LIABILITIES 17 - -
Contributed capital 82,518 82,518
Retained earnings 61,531 57,646
- ----------------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY 13 144,049 140,164
- ----------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 205,600 223,153
================================================================================================================
The accompanying notes are an integral part of these financial statements
2
LLC GEOILBENT
STATEMENTS OF INCOME
(expressed in thousand of US Dollars)
- ----------------------------------------------------------------------------------------------------------------
Year ended Year ended Year ended
Notes 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------
TOTAL SALES AND OTHER OPERATING REVENUES 14 91,598 101,159 78,805
- ----------------------------------------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Operating expenses 15,360 11,415 8,959
Selling and distribution expenses 6,696 9,876 4,612
General and administrative expenses 8,335 5,650 3,407
Depletion expense 9 27,168 14,918 9,556
Taxes other than income tax 15 27,657 26,011 18,286
- ----------------------------------------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS 85,216 67,870 44,820
================================================================================================================
OTHER INCOME AND EXPENSE
Exchange (gain)/ loss, net (2,053) (781) 597
Interest expense, net 4,629 7,547 7,438
Other non-operating (income)/ loss, net (381) (648) 724
- ----------------------------------------------------------------------------------------------------------------
TOTAL OTHER EXPENSE 2,195 6,118 8,759
- ----------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAX 4,187 27,171 25,226
- ----------------------------------------------------------------------------------------------------------------
INCOME TAX EXPENSE 15
Current income tax expense 2,804 6,751 6,321
Deferred income tax benefit (2,502) - -
- ----------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE 302 6,751 6,321
- ----------------------------------------------------------------------------------------------------------------
NET INCOME 3,885 20,420 18,905
================================================================================================================
The accompanying notes are an integral part of these financial statements
3
LLC GEOILBENT
STATEMENTS OF CASHFLOWS
(expressed in thousand of US Dollars)
- ----------------------------------------------------------------------------------------------------------------
Year ended Year ended Year ended
30 September 2002 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income 3,885 20,420 18,905
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion expense 27,168 14,918 9,556
Amortization of financing costs 520 520 520
Deferred income tax benefit (2,502) - -
Effect of foreign exchange on balance sheet
items (2,053) (781) 597
Decrease/(increase) in accounts receivable and
advances 403 85 (1,081)
Decrease/(increase) in inventories 6,362 (4,700) (2,666)
Increase/(decrease) in accounts payable (3,407) 11,902 6,624
Increase/(decrease) in trade advances (5,747) 3,785 5,067
Increase in taxes payable 5,436 4,780 515
Increase/(decrease) in other payables and accrued
expenses (1,378) (2,386) 608
- ----------------------------------------------------------------------------------------------------------------
Cash provided by operating activities 28,687 48,543 38,645
- ----------------------------------------------------------------------------------------------------------------
CASH FLOW FROM INVESTING ACTIVITIES
Additions to oil and gas producing properties (26,469) (39,683) (39,910)
Disposal/(purchase) of investments 367 (129) (27)
- ----------------------------------------------------------------------------------------------------------------
NET CASH USED IN INVESTING ACTIVITIES (26,102) (39,812) (39,937)
- ----------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of short-term borrowings from founders - (717) (4,534)
Payment of short-terms borrowings (3,000) (3,845) -
Proceeds from short-term borrowings - 6,446 2,602
Proceeds from long-term borrowings from founders 7,500 - -
Payments of long-term borrowings (18,200) (10,455) (140)
Decrease/(increase) in restricted cash 8,738 2,153 (2,889)
- ----------------------------------------------------------------------------------------------------------------
NET CASH USED IN FINANCING ACTIVITIES (4,962) (6,418) (4,961)
- ----------------------------------------------------------------------------------------------------------------
Effect of foreign exchange on cash balances (31) (37) (567)
- ----------------------------------------------------------------------------------------------------------------
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS (2,408) 2,276 (6,820)
Cash and cash equivalents, beginning of year 4,409 2,133 8,953
- ----------------------------------------------------------------------------------------------------------------
Cash and cash equivalents, end of year 2,001 4,409 2,133
================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid 4,862 7,609 5,536
Income taxes paid 2,747 6,906 5,523
The accompanying notes are an integral part of these financial statements
4
LLC GEOILBENT
STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(expressed in thousands of US Dollars except as indicated)
- ----------------------------------------------------------------------------------------------------------------
Total stockholders'
Contributed capital Retained earnings equity
- ----------------------------------------------------------------------------------------------------------------
BALANCE AT 30 SEPTEMBER 1999 82,518 18,321 100,839
================================================================================================================
Net income and total comprehensive income - 18,905 18,905
- ----------------------------------------------------------------------------------------------------------------
BALANCE AT 30 SEPTEMBER 2000 82,518 37,226 119,744
================================================================================================================
Net income and total comprehensive income - 20,420 20,420
- ----------------------------------------------------------------------------------------------------------------
BALANCE AT 30 SEPTEMBER 2001 82,518 57,646 140,164
================================================================================================================
Net income and total comprehensive income - 3,885 3,885
- ----------------------------------------------------------------------------------------------------------------
BALANCE AT 30 SEPTEMBER 2002 82,518 61,531 144,049
================================================================================================================
The accompanying notes are an integral part of these financial statements
5
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
NOTE 1: ORGANIZATION
LLC Geoilbent (the "Company") is engaged in the development and production of
oil and gas in the North Gubkinskoye and South Tarasovskoye fields. These fields
are located in the West Siberian region of the Russian Federation, approximately
2,000 miles northeast of Moscow. The Company was established in December 1991 by
two Russian oil companies, OAO Purneftegas ("PNG") and OAO Purneftegasgeologia
("PNGG"), and Harvest Natural Resources, Inc. ("Harvest", formerly, Benton Oil
and Gas Company) of the United States, which contributed 33%, 33% and 34%,
respectively, of the Company's charter capital, in accordance with the Company's
Foundation Document. In January 2002, PNG and PNGG transferred their stakes in
the Company to OAO Minley, an affiliated company.
NOTE 2: BASIS OF PRESENTATION
The Company maintains its accounting records and prepares its statutory
financial statements in accordance with the Regulations on Accounting and
Reporting of the Russian Federation ("RAR"). The accompanying financial
statements have been prepared from these accounting records and adjusted as
necessary to comply with accounting principles generally accepted in the United
States of America ("US GAAP"). The Company has a year ending of 30 September for
US GAAP reporting purposes.
In preparing the financial statements in conformity with US GAAP, management
makes estimates and assumptions that affect the reported amounts of assets and
liabilities, revenues and expenses and the disclosure of contingent assets and
liabilities. Actual results could differ from such estimates.
Certain previously presented amounts have been reclassified to conform to the
presentation adopted during the current period. These reclassifications had no
impact on previously reported retained earnings.
REPORTING AND FUNCTIONAL CURRENCY. The Russian Rouble is the functional currency
(primary currency in which business is conducted) for the Company's operations
in the Russian Federation. The Company considers the US dollar as its reporting
currency as a significant portion of its business is conducted in US dollars and
management uses the US dollar to manage business risks and exposures, and to
measure performance of its business.
The measurement currency of the Company is either the Russian Rouble or the US
dollar depending on the nature of the activities. The transactions and balances
of the accompanying financial statements not already measured in US dollars have
been remeasured into US dollars in accordance with the relevant provisions of
SFAS No. 52 Foreign Currency Translation as applied to hyperinflationary
economies. Consequently, monetary assets and liabilities are translated at
closing exchange rates and non-monetary items are translated at historic
exchange rates and adjusted for any impairments. The statements of income and
cash flows have been translated using average exchange rates for the reporting
period. Translation differences resulting from the use of these exchange rates
have been included in the determination of net income and are included in
exchange gains/losses in the accompanying statements of income. The exchange
rates at 30 September 2002, and 30 September 2001, were 31.64 and 29.39,
respectively, Russian Roubles per US dollar.
6
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
Inflation, exchange restriction and controls. Exchange restrictions and controls
exist relating to converting Russian Roubles to other currencies. At present,
the Russian Rouble is not a convertible currency outside the Russian Federation.
Future movements in the exchange rates between the Russian Rouble and the US
dollar will affect the carrying value of the Company's Russian Rouble
denominated assets and liabilities. Such movements may also affect the Company's
ability to realize non-monetary assets represented in US dollars in the
accompanying financial statements. Accordingly, any translation of Russian
Rouble amounts to US dollars should not be construed as a representation that
such Russian Rouble amounts have been, could be, or will in the future be
converted into US dollars at the exchange rate shown or at any other exchange
rate.
NOTE 3: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CASH AND CASH EQUIVALENTS. Cash and cash equivalents include all highly liquid
securities with original maturities of three months or less when acquired.
ACCOUNTS RECEIVABLE. Accounts receivable are presented at net realizable value
and include value-added and excise taxes which are payable to tax authorities
upon collection of such receivables.
INVENTORIES. Crude oil and petroleum products inventories are valued at the
lower of cost, using the first-in-first out method, or net realizable value.
Materials and supplies inventories are recorded at the lower of average cost or
net realizable value.
PROPERTY, PLANT AND EQUIPMENT. The Company follows the full cost method of
accounting for oil and gas properties. Under this method, all oil and gas
property acquisition, exploration, and development costs including internal
costs directly attributable to such activities are capitalized as incurred in
the Company's one cost center (full cost pool), which is the Russian Federation.
Payroll and other internal costs capitalized include salaries and related fringe
benefits paid to employees directly engaged in the acquisition, exploration and
development of oil and gas properties as well as all other directly identifiable
internal costs associated with these activities. Payroll and other internal
costs associated with production operations and general corporate activities are
expensed in the period incurred.
The full cost pool, including future development costs (including estimated
dismantlement, restoration and abandonment costs), net of prior accumulated
depletion, is depleted using the unit-of-production method based upon actual
production and estimates of proved oil and gas reserve quantities. Proceeds from
sales of oil and gas properties are credited to the full cost pool with no gain
or loss recognized unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves of oil and gas.
Pursuant to full cost accounting rules, capitalized costs less related
accumulated depletion and deferred income taxes may not exceed the sum of (1)
the present value of future net revenue from estimated production of proved oil
and gas reserves discounted at 10 percent; plus (2) the cost of properties not
being amortized, if any; plus (3) the lower of cost or estimated fair value of
unproved properties included in the costs being amortized, if any; less (4)
income tax effects related to differences in the book and tax basis of oil and
gas properties.
7
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
PENSION AND POST-EMPLOYMENT BENEFITS. The Company's mandatory contributions to
the governmental pension scheme are expensed when incurred.
REVENUE RECOGNITION. Revenue from the sale of crude oil is recognized when it is
dispatched to customers and title has transferred.
INCOME TAXES. Deferred income tax assets and liabilities are recognized for
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases, in accordance with SFAS No. 109, Accounting for Income
Taxes. Deferred income tax assets and liabilities are measured using enacted tax
rates in the years in which these temporary differences are expected to reverse.
Valuation allowances are provided for deferred income tax assets when management
believes it is more likely than not that the assets will not be realized.
RECENT ACCOUNTING STANDARDS. In July 2001, the Financial Accounting Standards
Board (the "FASB") issued Statement of Financial Accounting Standards ("SFAS")
No. 142, Goodwill and Other Intangible Assets ("SFAS 142"). SFAS 142 requires
that goodwill and intangible assets with indefinite lives no longer be amortized
and requires that such goodwill and intangible assets be tested annually for
impairment. SFAS 142 is effective for fiscal years beginning after December 15,
2001. Management does not believe that the adoption of SFAS 142 will have a
material effect on the Company's financial position or results of operations.
In September 2001, the FASB issued SFAS No. 143, Accounting for Assets
Retirement Obligations ("SFAS 143"). SFAS No. 143 requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of
the related long-lived asset. Subsequently, the asset retirement costs should be
allocated to expense using a systematic and rational method. SFAS No. 143 is
effective for fiscal years beginning after 15 June 2002. The Company has not yet
assessed the impact of SFAS No. 143 and therefore, at this time cannot
reasonably estimate the effect of this statement on its financial condition and
results of operations.
In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets ("SFAS 144"), which clarified certain
implementation issues arising from SFAS 121. SFAS 144 is effective for years
beginning after December 15, 2001. Management does not believe that the adoption
of SFAS 144 will have a material effect on the Company's financial position or
results of operations.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities ("SFAS 146"). SFAS 146 addresses the recognition,
measurement, and reporting of costs associated with exit and disposal
activities, including restructuring activities, and nullifies the guidance in
Emerging Issues Task Force Issue No. 94-3. SFAS 146 is effective for exit or
disposal activities initiated after December 31, 2002. Management does not
believe that the adoption of SFAS 146 will have a material effect on the
Company's financial position or results of operations.
In November 2002, the International Practices Task Force (IPTF) concluded that
Russia has ceased being a highly inflationary economy as of 1 January 2003. As a
result of the Task Force conclusion, companies reporting under US GAAP in Russia
will be required to apply
8
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
the guidance contained in EITF No. 92-4 and EITF No. 92-8 as of 1 January 2003.
Management has not yet estimated the effect that EITF No. 92-4 and EITF No. 92-8
will have on the Company.
NOTE 4: GOING CONCERN
During the year ended 30 September 2002 the Company took steps to reduce its
working capital deficit. This included the renegotiation of debt falling due for
repayment to the European Bank for Reconstruction and Development (the "EBRD")
(Note 11), the repayment of debt, and the receipt of subordinated long-term
loans from the Company's stockholders. However, as at 30 September 2002, and 30
September 2001, the current liabilities of the Company exceeded its current
assets by USD 35,266 thousand and USD 24,992 thousand, respectively. Included in
current liabilities as at 30 September 2002 are loans repayable to the EBRD of
USD 22,000 thousand. This debt has been classified as current because the
Company will not be able to implement a new management information system by 1
May 2003, as required by the loan facility, and therefore will be in violation
of the loan facility covenants. Under the terms of the loan facility the EBRD
may declare the loan to be in default and can accelerate the maturity. The loan
facility also requires the Company to maintain a minimum working capital ratio.
The amended loan agreement discussed in Note 11 waived the maintenance of this
ratio through 30 September 2002. The Company's plans to re-establish the
required level of working capital is dependent upon the EBRD advancing
additional funds to the Company under the amended loan facility by 31 March
2003. There can be no assurance that the EBRD will provide this funding by 31
March 2003.
Because of the Company's significant working capital deficit, a substantial
portion of its cash flow must be utilized to pay accounts and taxes payable.
Additionally, in order to maintain or increase proved oil and gas reserves, the
Company must make substantial capital expenditures in 2003 and subsequently. The
Company's cash flow from operations is dependent on the level of oil prices,
which are historically volatile and are significantly impacted by the proportion
of production that the Company can sell on the export market. Historically, the
Company has supplemented its cash flow from operations with additional
borrowings or equity capital and may continue to do so. Should oil prices
decline for a prolonged period and should the Company not have access to
additional capital, the Company would need to reduce its capital expenditures,
which could limit its ability to maintain or increase production and, in turn,
meet its debt service requirements. Asset sales and financing are restricted
under the terms of debt agreements.
Management plans to further address the Company's working capital deficit by
reducing certain capital expenditures and funding its 2003 debt service and
planned capital expenditures with cash flows from existing producing properties
and its development drilling program. Additionally, the Company is working with
the EBRD to resolve issues relating to the loan covenant violations. The
accompanying financial statements do not include any adjustments that might
result if the Company were unable to continue as a going concern.
NOTE 5: CASH AND CASH EQUIVALENTS
Included in cash and cash equivalents as at 30 September 2002, and 2001,
respectively, are Russian Rouble denominated amounts totaling RR 18.3 million
(USD 578 thousand) and RR 129.4 million (USD 4,402 thousand).
9
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
Restricted cash consists of deposits with lending institutions to pay interest
and principal as discussed in Note 11. As at 30 September 2002, the amount of
restricted cash was USD 1,469 thousand (2001: USD 10,208 thousand). These
accounts are maintained in offshore US Dollar denominated accounts.
NOTE 6: FINANCIAL INSTRUMENTS
FAIR VALUES. The estimated fair values of financial instruments are determined
with reference to various market information and other valuation methodologies
as considered appropriate, however considerable judgment is required in
interpreting market data to develop these estimates. Accordingly, the estimates
are not necessarily indicative of the amounts that the Company could realize in
a current market transaction. The methods and assumptions used to estimate fair
value of each class of financial instrument are presented below.
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE. The
carrying amount of these items are a reasonable approximation of their fair
value.
SHORT-TERM AND LONG-TERM DEBT. Loan arrangements have both fixed and variable
interest rates that reflect the currently available terms and conditions for
similar debt. The carrying value of this debt is a reasonable approximation of
its fair value.
CREDIT RISKS. A significant portion of the Company's accounts receivable are
from domestic and foreign customers, and advances are made to domestic
suppliers. Although collection of these amounts could be influenced by economic
factors affecting these entities, management believes there is no significant
risk of loss to the Company beyond the provisions already recorded, provided
that economic difficulties in the Russian Federation do not deteriorate (Note
17).
NOTE 7: ACCOUNTS RECEIVABLE AND ADVANCES TO SUPPLIERS
Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------
Trade accounts receivable 1,387 2,158
Recoverable value-added tax 3,515 3,640
Advances to suppliers 1,193 723
Advances to customs 137 597
Other receivables 76 147
- ---------------------------------------------------------------------------------------------------------------
TOTAL ACCOUNTS RECEIVABLE AND ADVANCES TO SUPPLIERS 6,308 7,265
===============================================================================================================
10
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
NOTE 8: INVENTORIES
Thousands of US Dollars 30 September 2002 30 September 2001
--------------------------------------------------------------------------------------------------------------
Materials and supplies 6,905 12,814
Crude oil 296 751
--------------------------------------------------------------------------------------------------------------
TOTAL INVENTORIES 7,201 13,565
===============================================================================================================
NOTE 9: OIL AND GAS PRODUCING PROPERTIES
Thousands of US dollars 30 September 2002 30 September 2001
--------------------------------------------------------------------------------------------------------------
Oil and gas producing properties, cost 278,459 251,990
Accumulated depletion (92,470) (65,302)
--------------------------------------------------------------------------------------------------------------
OIL AND GAS PRODUCING PROPERTIES, NET BOOK VALUE 185,989 186,688
===============================================================================================================
The Company's oil and gas fields are situated on land belonging to the
Government of the Russian Federation. The Company obtained licenses from the
local authorities and pays unified production taxes to explore and produce oil
and gas from these fields. Licenses will expire in September 2018 for the North
Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However,
under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the
licenses may be extended over the economic life of the lease at the Company's
option. Management intends to extend such licenses for properties that are
expected to produce subsequent to their expiry dates. Estimates of proved
reserves extending past 2018 represent approximately 5 percent of total proved
reserves.
Temporarily excluded from the full cost oil and gas properties depletion pool as
at 30 September 2002 are costs incurred to date of USD 800 thousand relating to
unevaluated projects for a gas processing plant and geological and geophysical
work for the Urabor-Yahinskoe exploration license, for both of which the
ultimate feasibility and estimates of proven reserves have not yet been
established. Management expects that decisions regarding completion of both
projects will be taken during the next year.
NOTE 10: SHORT-TERM BORROWINGS
Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------
International Moscow Bank ("IMB") - 3,000
- ---------------------------------------------------------------------------------------------------------------
TOTAL SHORT-TERM BORROWINGS - 3,000
===============================================================================================================
NOTE 11: LONG-TERM DEBT
Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------
EBRD 22,000 33,000
IMB 550 7,750
Subordinated loans - related parties 7,500 -
Less: current portion ( 22,550) (18,200)
- ---------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 7,500 22,550
===============================================================================================================
11
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
EBRD LOAN. At 30 September 2002, the outstanding balance of loans with the EBRD
totaled USD 22 million. On 23 September 2002, the Company signed an amended loan
agreement with the EBRD for the maximum borrowing of USD 50 million. This
amended loan facility became effective subsequent to 30 September 2002. Under
the loan agreement, the use of loan proceeds is restricted to the repayment of
accounts payable and development of oil and gas reserves. The new loan facility
is to be repaid in 6 equal semi-annual installments commencing January 2004. The
interest rate under the new loan agreement is linked to the London interbank
offer rate ("LIBOR") and an agreed upon margin. The Company must hold as
restricted cash 30 percent of the total of principal and interest to be paid at
the next repayment date.
LIBOR interest rates ranged from 1.84 percent to 3.5 percent in 2002 (2001: 3.5
percent to 6.94 percent, 2000: 6.6063 to 7.064 percent). The annual weighted
average interest rates on these loans varied between 8.59 percent and 11.71
percent for the year ended 30 September 2002 (2001: 14.93 percent and 15.17
percent, 2000: 10.88 percent and 15.14 percent). The outstanding loan amount to
the EBRD is collaterized by most significant immovable assets and crude oil
export sales of the Company.
The EBRD loan agreement includes certain covenants which include, among other
things, the maintenance of financial ratios. If the Company fails to meet these
requirements for two concecutive quarters it will result in an event of default
whereby the EBRD may, at its option, demand payment of the outstanding principal
and interest. Although the Company was not in compliance with maintaining its
current ratio requirement of 1.1 as at 30 September 2002, as part of the amended
loan facility discussed above, the EBRD has waived the covenant requirement
through the quarters ended September 2002. As dicussed in Note 4, the Company
will be in violation of the loan facility covenants which would allow the EBRD
to declare a default and accelerate the maturity of this loan. The Company has
accordingly classified the USD 22,000 in debt as a current liability.
SUBORDINATED LOANS - RELATED PARTIES. During 2002, stockholders OAO Minley and
Harvest Natural Resources provided the Company with subordinated loans totaling
USD 7.5 million. The loans are unsecured and repayable commencing January 2004.
Interest rates are set at 2% for the Minley loan, and LIBOR for the Harvest
loan.
IMB LOAN. On 14 May 2001, the Company obtained a USD 3.3 million loan from IMB
repayable by six payments of USD 0.55 million commencing 1 August 2001, ending 1
November 2002, bearing interest of LIBOR plus 6.5 percent. The loan is
collaterized by moveable property of the South-Tarasovskoye field.
Aggregate maturities of long-term debt outstanding at 30 September 2002 are as
follows:
Thousands of US dollars
- ---------------------------------------------------------------------------------------------------------------
Year ended 30 September 2004 7,500
- ---------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 7,500
===============================================================================================================
12
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
NOTE 12: TAXES PAYABLE
Taxes payable were as follows:
Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------
Value Added Tax 1,445 3,305
Income tax 1,176 1,826
Royalty 896 923
Mineral restoration tax 152 767
Road users tax 642 176
Unified production tax 6,703 -
Property taxes 1,121 438
Other taxes 219 49
- ---------------------------------------------------------------------------------------------------------------
TOTAL TAXES PAYABLE 12,354 7,484
===============================================================================================================
NOTE 13: CONTRIBUTED CAPITAL
Capital contributions are as follows:
Thousands of US dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------
Purneftegasgeologia - 27,645
Purneftegas - 27,088
Harvest Natural Resources 27,785 27,785
OAO Minley 54,733 -
- ---------------------------------------------------------------------------------------------------------------
TOTAL CONTRIBUTED CAPITAL 82,518 82,518
===============================================================================================================
All capital contributions have been made since inception in accordance with the
Company's Foundation Document.
Reserves available for distribution to shareholders are based on the statutory
accounting reports of the Company, which are prepared in accordance with
Regulations on Accounting and Reporting of the Russian Federation and which
differ from U.S. GAAP. Russian legislation identifies the basis of distribution
as net income. For 2001, the current year statutory net income for the Company
as reported in the annual statutory accounting reports was RR 551 million.
However, current legislation and other statutory laws and regulations dealing
with distribution rights are open to legal interpretation and, consequently,
actual distributable reserves may differ from the amount disclosed.
NOTE 14: REVENUES
Revenues for the years ended 30 September 2002, 2001 and 2000, consisted of the
following:
Thousand of US dollars 30 September 2002 30 September 2001 30 September 2000
- ---------------------------------------------------------------------------------------------------------------
Crude oil - export (Europe and CIS) 47,751 83,889 50,807
Crude oil - domestic 40,778 10,900 13,195
Refined products - domestic 2,764 6,231 14,733
Other operating revenues 305 139 70
- ---------------------------------------------------------------------------------------------------------------
TOTAL SALES AND OTHER OPERATING REVENUES 91,598 101,159 78,805
===============================================================================================================
13
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
NOTE 15: TAXES
Presented below is a reconciliation between the provision for income taxes and
taxes determined by applying the statutory tax rate as applied in the Russian
Federation to income before income taxes.
Thousand of US dollars 30 September 2002 30 September 2001 30 September 2000
- -----------------------------------------------------------------------------------------------------------------
Income before income taxes 4,187 27,171 25,226
- -----------------------------------------------------------------------------------------------------------------
Theoretical income tax expense at statutory rate 1,005 9,509 7,568
(24% in 2002; 35% in 2001; 30% in 2000)
Increase (reduction) due to:
Change in valuation allowance 80 1,810 348
Non-deductible expenses 2,894 2,693 2,600
Investment tax credits (5,348) (6,821) (5,142)
Change in statutory tax rate 595 (750) -
Tax penalties and interest 1,135 517 27
Foreign exchange effects and other (59) (207) 920
- -----------------------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE 302 6,751 6,321
=================================================================================================================
Deferred income taxes reflect the impact of temporary differences between the
amount of assets and liabilities recognized for financial reporting purposes and
such amounts recognized for statutory tax purposes. Net deferred tax assets are
comprised of the following, at 30 September 2002 and 2001:
Thousand of US dollars 30 September 2002 30 September 2001
- -----------------------------------------------------------------------------------------------------------------
Inventories 93 137
Accounts receivable 258 -
Accounts payable and accrued liabilities 430 -
Losses carried forward 2,502 2,403
Property, plant and equipment 4,810 2,971
- -----------------------------------------------------------------------------------------------------------------
Total deferred tax assets 8,093 5,511
Less: Valuation allowance (5,591) (5,511)
- -----------------------------------------------------------------------------------------------------------------
NET DEFERRED TAX ASSET 2,502 -
=================================================================================================================
Losses carried forward represent those losses for tax purposes which, according
to legislation, the Company is permitted to offset against future taxable
earnings in the periods up to 2008, and is subject to limitations of no more
than 30% of the Company's tax liabilities for the tax reporting period.
As at 30 September 2002, management of the Company have assessed the
recoverability of the Company's deferred tax assets and believes that with
changes in the tax law it will now be able to realize the tax losses carried
forward. Accordingly, the Company has provided a valuation allowance as at 30
September 2002, and 2001, of USD 5,591 thousand and USD 5,304 thousand,
respectively, against the amount of deferred tax assets.
Deferred income taxes are classified as follows:
Thousands of US dollars 30 September 2002 30 September 2001
----------------------------------------------------------------------------------------------------------------
Deferred income tax, current 1,806 -
Deferred income tax, non-current 696 -
----------------------------------------------------------------------------------------------------------------
TOTAL NET DEFERRED TAX ASSET 2,502 -
=================================================================================================================
14
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
TAXES OTHER THAN INCOME TAX. The Company is subject to a number of taxes other
than on income which are detailed below.
Thousands of US dollars 30 September 2002 30 September 2001 30 September 2000
- ---------------------------------------------------------------------------------------------------------------
Export duties 5,376 10,922 4,322
Excise tax 535 1,548 813
Royalty 2,254 4,867 4,028
Mineral restoration tax 885 4,596 4,510
Road users tax 860 1,427 2,201
Unified production tax 14,221 - -
Property taxes 1,994 1,424 780
Other taxes 1,532 1,227 1,632
- ---------------------------------------------------------------------------------------------------------------
TOTAL TAXES OTHER THAN INCOME TAX 27,657 26,011 18,286
===============================================================================================================
Beginning 1 January 2002, mineral restoration tax, royalty tax and excise tax on
crude oil production were abolished and replaced by the unified natural
resources production tax. Through 31 December 2004, the base rate for the
unified natural resources production tax is set at RR 340 per metric ton of
crude oil produced, and is to be adjusted depending on the market price of Urals
blend and the RR/USD exchange rate. The tax becomes nil if the Urals blend price
falls to or below USD 8.00 per barrel. From 1 January 2005, the unified natural
resources production tax rate is set by law at 16.5 percent of crude oil
revenues recognized by the Company based on Regulations on Accounting and
Reporting of the Russian Federation.
NOTE 16: RELATED PARTY TRANSACTIONS
As of 30 September 2002 and 2001, the Company had the following balances with
its stockholders. These balances are included in the balance sheet within
accounts receivable, accounts payable and long-term debt as appropriate.
Thousand of US Dollars 30 September 2002 30 September 2001
- ---------------------------------------------------------------------------------------------------------------
Accounts receivable
Purneftegasgeologia and affiliated entities 63 -
Accounts payable
Purneftegasgeologia and affiliated entities 574 2,113
Purneftegas and affiliated entities 22 182
Harvest Natural Resources 3,354 -
Long-term debt
Harvest Natural Resources 2,500 -
Minley 5,000 -
- ---------------------------------------------------------------------------------------------------------------
TOTAL 11,513 2,295
===============================================================================================================
HARVEST NATURAL RESOURCES. Accounts payable as of 30 September 2002 resulted
from Harvest providing insurance on behalf of the Company and personnel
services. During 2001 and 2000 the Company paid to Harvest USD 717 thousand and
USD 2,000, respectively, for prepaid loan costs relating to the creation of the
EBRD/IMB loans.
PURNEFTEGAS. During 2002, 2001 and 2000, Purneftegas and affiliated entities
provided well maintenance services and supplies to the Company for a total value
of approximately USD
15
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
312 thousand, USD 248 thousand, and USD 188 thousand, respectively. The Company
sold materials to PNG and affiliated entities during 2002 for a total value of
approximately USD 260 thousand.
PURNEFTEGASGEOLOGIA. During 2002, 2001 and 2000, Purneftegasgeologia and
affiliated entities provided services to the Company for a total value of
approximately USD 2,414 thousand, USD 4,193 thousand, and USD 2,156 thousand,
respectively. Services consisted of drilling, well maintenance and other related
work. The Company sold crude oil to PNGG and affiliated entities for a total
value of USD 24 thousand, USD 56 thousand, and USD 80 thousand during 2002,
2001, and 2000, respectively, and materials during 2002 for a total value of
approximately USD 613 thousand.
MINLEY. During 2002, the Company paid USD 4.9 million to Minley in settlement at
face value of promissory notes originally issued to the Company's suppliers and
contractors.
NOTE 17: COMMITMENTS AND CONTINGENT LIABILITIES
ECONOMIC AND OPERATING ENVIRONMENT IN THE RUSSIAN FEDERATION. Whilst there have
been improvements in the economic situation in the Russian Federation in recent
years, the country continues to display some characteristics of an emerging
market. These characteristics include, but are not limited to, the existence of
a currency that is not freely convertible in most countries outside of the
Russian Federation, restrictive currency controls, and relatively high
inflation.
The prospects for future economic stability in the Russian Federation are
largely dependent upon the effectiveness of economic measures undertaken by the
government, together with legal, regulatory, and political developments.
TAXATION. Russian tax legislation is subject to varying interpretations and
changes occurring frequently, which may be retroactive. Further, the
interpretation of tax legislation by tax authorities as applied to the
transactions and activity of the Company may not coincide with that of
management. As a result, the tax authorities may challenge transactions and the
Company may be assessed additional taxes, penalties and interest, which may be
significant. The tax periods remain open to review by the tax and customs
authorities for three years. The Company cannot predict the ultimate amount of
additional assessments, if any, and the timing of their related settlements with
certainty, but expects that additional liabilities, if any, arising will not
have a significant effect on the accompanying financial statements.
ENVIRONMENTAL MATTERS. Environmental regulations and their enforcement are
continually being considered by governmental authorities, and the Company
periodically evaluates its obligations related thereto. As obligations are
determined, they are provided over the estimated remaining lives of the related
oil and gas reserves, or recognized immediately, depending on their nature. The
outcome of environmental liabilities under proposed or any future legislation,
or as a result of stricter enforcement of existing legislation, cannot
reasonably be estimated. Under existing legislation, management believes there
are no probable liabilities, which would have a materially adverse effect on the
financial position or the results of the Company.
16
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
LEGAL CONTINGENCIES. The Company is currently seeking to recover from tax
authorities royalty taxes paid during the period from 1996 to 2001 in the amount
of approximately RR 217 million ($6.9 million) based on the Company's
interpretation of applicable laws and regulations during this period. The case
is currently being heard in the courts and the final outcome is uncertain at
this time. No asset has been recognized related to this claim.
The Company is the named defendant in a number of lawsuits as well as the named
party in numerous other proceedings arising in the ordinary course of business.
While the outcomes of such contingencies, lawsuits or other proceedings cannot
be determined at present, management believes that any resulting liabilities
will not have a materially adverse effect on the operating results or the
financial position of the Company
INSURANCE. At 30 September 2002 and 2001, the Company held limited insurance
policies in relation to its assets and operations, or in respect of public
liability or other insurable risks. Since the absence of insurance alone does
not indicate that an asset has been impaired or a liability incurred, no
provision has been made in the financial statements for unspecified losses.
17
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
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:
Year ended Year ended Year ended
Thousand of US Dollars 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------
Development costs 25,004 33,583 39,087
Exploration costs 1,465 6,100 823
- ----------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED IN OIL AND NATURAL GAS 26,469 39,683 39,910
ACQUISITION, EXPLORATION, AND DEVELOPMENT
ACTIVITIES
================================================================================================================
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING
ACTIVITIES:
As at As at
Thousand of US Dollars 30 September 2002 30 September 2001
- ----------------------------------------------------------------------------------------------------------------
Proved property costs 277,659 251,990
Costs excluded from amortization 800 -
Oilfield inventories 6,905 12,814
Less accumulated depletion and impairment (92,470) (65,302)
- ----------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING
ACTIVITIES 192,894 199,502
================================================================================================================
TABLE III - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES:
In accordance with SFAS 69, results of operations for oil and natural gas
producing activities neither include general corporate overhead and monetary
effects, nor their associated tax effects. Income tax is based on statutory
rates for the year, adjusted for tax deductions, tax credits and allowances.
18
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
Year ended Year ended Year ended
Thousand of US Dollars 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------
Oil and natural gas sales 91,291 100,768 78,577
Expenses:
Operating, selling and distribution expenses
and taxes other than on income 49,713 47,302 31,856
Depletion 27,168 14,918 9,557
Income tax expense 5,750 11,006 9,723
--------------------------------------------------------------
Total expenses 82,361 73,226 51,136
- ----------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS
PRODUCING ACTIVITIES 8,660 27,542 27,441
================================================================================================================
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.
The Company's oil and gas fields are situated on land belonging to the
Government of the Russian Federation. The Company obtained licenses from the
local authorities and pays unified production taxes to explore and produce oil
and gas from these fields. Licenses will expire in September 2018 for the North
Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However,
under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the
licenses may be extended over the economic life of the lease at the Company's
option. Management intends to extend such licenses for properties that are
expected to produce subsequent to their expiry dates. Estimates of proved
reserves extending past 2018 represent approximately 5 percent of total proved
reserves.
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.
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
19
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
non producing 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.
The evaluations of the oil and natural gas reserves were prepared by Ryder-Scott
Company, independent petroleum engineers.
PROVED RESERVES-CRUDE OIL, CONDENSATE AND Year ended Year ended Year ended
NATURAL GAS LIQUIDS (MBbls) 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------
PROVED RESERVES BEGINNING OF YEAR 87,259 95,924 107,100
Revisions of previous estimates (10,163) (16,454) (20,306)
Extensions, discoveries and improved recovery 4,391 12,974 13,377
Production (6,912) (5,185) (4,247)
- ----------------------------------------------------------------------------------------------------------------
PROVED RESERVES, END OF YEAR 74,575 87,259 95,924
================================================================================================================
PROVED DEVELOPED RESERVES 34,824 46,052 43,861
================================================================================================================
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
20
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in US Dollars except as indicated)
- --------------------------------------------------------------------------------
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.
Year ended Year ended Year ended
Thousand of US Dollars 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------
Future cash inflow 1,381,874 1,277,494 2,026,415
Future production costs (599,277) (739,221) (1,224,824)
Future development costs (119,725) (108,882) (100,103)
- ----------------------------------------------------------------------------------------------------------------
Future net revenue before income taxes 662,872 429,391 701,488
10% annual discount for estimated timing of cash
flows (318,079) (190,788) (289,253)
- ----------------------------------------------------------------------------------------------------------------
Discounted future net cash flows before income taxes 344,793 238,603 412,235
Future income taxes, discounted at 10% per annum (71,442) (30,815) (74,809)
- ----------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS 273,351 207,788 337,426
================================================================================================================
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
Year ended Year ended Year ended
Thousand of US Dollars 30 September 2002 30 September 2001 30 September 2000
- ----------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT BEGINNING OF PERIOD 207,788 337,426 497,285
Sales of oil and natural gas, net of related costs (69,541) (54,015) (59,344)
Revisions to estimates of proved reserves:
Net changes in prices, development and
production costs 225,132 (107,356) (148,965)
Quantities (29,432) (71,709) 57,424
Extensions, discoveries and improved recovery,
net of future costs 5,974 55,197 (92,559)
Accretion of discount 23,862 41,224 63,338
Net change of income taxes 3,367 43,994 61,282
Development costs incurred 26,468 37,953 22,391
Changes in timing and other (120,267) (74,926) (63,426)
- ----------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT END OF PERIOD 273,351 207,788 337,426
================================================================================================================
21
EXHIBIT INDEX
EXHIBIT
NO.NUMBER DESCRIPTION
-
------- -----------
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 (Incorporated by reference to Exhibit 3.3 to
our Form 10-Q, filed August 13, 2001).
4.1 Form of Common Stock Certificate (Previously filed as an
exhibit to our S-1 Registration Statement (Registration No.
33-26333)).
4.2 Certificate of Designation, Rights and Preferences of the
Series B. Preferred Stock of Benton Oil and Gas Company,
filed May 12, 1995. (Previously filed as an Exhibit 4.1 to
our Form 10-Q filed on May 13, 2002, File No. 1-10762.)
4.3 Rights Agreement between Benton Oil and Gas Company and
First Interstate Bank, Rights Agent dated April 28, 1995.
(Previously filed as Exhibit 4.1 to our Form 10-Q filed on
August 13, 2002, File No. 1-10762.)
10.1 Form of Employment Agreements (Exhibit 10.19) (Previously
filed as an exhibit to our S-1 Registration Statement
(Registration No. 33-26333)).
10.2 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)).
10.3 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)).
10.4 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)).
10.510.3 Operating Service Agreement between Benton Oil and Gas
Company 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 -- ExhibitCommission--Exhibit 10.25) (Previously filed as an exhibit
to our S-1 Registration Statement (Registration No.
33-52436)).
10.6 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).
10.710.4 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 20072007. (Incorporated
by reference to Exhibit 10.1 to our Form 10-Q for the
quarter ended September 30, 1997).
10.8 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).
10.9 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).
10.10 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).
10.11 Benton Oil and Gas Company 1999 Employee Stock Option Plan
(Incorporated by reference to Exhibit 10.21 to our Form
10-K, filed on April 2, 2001).
10.12 Benton Oil and Gas Company Non-Employee Director Stock
Purchase Plan (Incorporated by reference to Exhibit 10.21 to
our Form 10-K, filed on April 2, 2001).
10.13 Employment Agreement dated December 7, 2000 between Benton
Oil and Gas Company and Steven W. Tholen (Incorporated by
reference to Exhibit 10.21 to our Form 10-K, filed on April
2, 2001).
10.141997, File No. 1-10762.)
10.5 Note payable agreement dated March 8, 2001 between
Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a
note in the principal amount of $6,000,000 with interest at
LIBOR plus five percent, for financing of Tucupita Pipeline
(Incorporated by reference to Exhibit 10.24 to our Form
10-Q, filed on May 15, 2001).
EXHIBIT
NO. DESCRIPTION
- ------- -----------
10.152001, File No. 1-10762).
10.6 Note payable agreement dated March 8, 2001 between
Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a
note in the principal amount of 4,435,200,000 Venezuelan
Bolivars (approximately $6.3 million) at a floating interest
rate, for financing of Tucupita Pipeline (Incorporated by
reference to Exhibit 10.25 to our Form 10-Q, filed on May
15, 2001)2001, File No. 1-10762.).
10.1610.7 Change of Control Severance Agreement effective May 4, 2001
(Incorporated by reference to Exhibit 10.26 to our Form
10-Q, filed on August 13, 2001)2001, File No. 1-10762.).
10.1710.8 Alexander E. Benton Settlement and Release Agreement
effective May 11, 2001 (Incorporated by reference to Exhibit
10.27 to our Form 10-Q, filed on August 13, 2001)2001, File No.
1-10762.).
10.18 Michael B. Wray Termination Agreement effective May 7, 2001
(Incorporated by reference to Exhibit 10.28 to our Form
10-Q, filed on August 13, 2001).
10.19 Michael B. Wray Consulting Agreement effective May 7, 2001
(Incorporated by reference to Exhibit 10.29 to our Form
10-Q, filed on August 13, 2001).
10.20 Relocation/Reduction in Force Severance Plan effective June
5, 2001 (Incorporated by reference to Exhibit 10.30 to our
Form 10-Q, filed on August 13, 2001).
10.2110.9 First Amendment to Change of Control Severance Plan
effective June 5, 2001 (Incorporated by reference to Exhibit
10.31 to our Form 10-Q, filed on August 13, 2001)2001, File No.
1-10762.).
10.22 Amended Benton Oil and Gas Company Non-Employee Director
Stock Purchase Plan (Incorporated by reference to Exhibit
10.1 to our Form 10-Q, filed on November 31, 2001)
10.23 Employment Agreement dated December 20, 2000 between Benton
Oil and Gas Company and Robert Stephen Molina.
10.24 Employment Agreement dated November 14, 2001, between Benton
Oil and Gas Company and Kurt A. Nelson.
10.2510.10 Sale and Purchase Agreement dated February 27, 2002 between
Benton Oil and Gas Company and Sequential Holdings Russian
Investors Limited regarding the sale of Benton Oil and Gas
Company's 68 percent interest in Arctic Gas Company.
(Incorporated by reference to Exhibit 10.25 to our Form 10-K
filed on March 28, 2002, File No. 1-10762.)
10.11 2001 Long Term Stock Incentive Plan (Incorporated by
reference to Exhibit 4.1 to our S-8 (Registration Statement
No. 333-85900)).
10.12 Subordinated Loan Agreement US$2,500,000 between Limited
Liability Company "Geoilbent" as borrower, and Harvest
Natural Resources, Inc. as lender. (Incorporated by
reference to Exhibit 10.2 to our Form 10-Q filed on August
13, 2002.)
10.13 Addendum No. 2 to Operating Services Agreement Monagas SUR
dated 19th September, 2002. (Incorporated by reference to
Exhibit 10.4 to our Form 10-Q filed on November 8, 2002,
File No. 1-10762.)
10.14 Bank Loan Agreement between Banco Mercantil, C.A. and
Benton-Vinccler C.A. dated October 1, 2002. (Incorporated by
reference to Exhibit 10.5 to our Form 10-Q filed on November
8, 2002, File No. 1-10762.)
10.15 Guaranty issued by Harvest Natural Resources, Inc. dated
September 26, 2002. (Incorporated by reference to Exhibit
10.6 to our Form 10-Q filed on November 8, 2002, File No.
1-10762.)
10.16 Amending and Restating the Credit Agreement between Limited
Liability Company "Geoilbent" and European Bank for
Reconstruction and Development dated 23rd September 2002.
(Incorporated by reference to Exhibit 10.7 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)
10.17 Amendment Agreement relating to Performance, Subordination
and Share Retention Agreement dated 30th September, 2002.
(Incorporated by reference to Exhibit 10.8 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)
10.18 Amending and Restating the Agreement for Pledge of Shares in
Limited Liability Company "Geoilbent" dated 23rd June, 1997.
(Incorporated by reference to Exhibit 10.9 to our Form 10-Q
filed on November 8, 2002, File No. 1-10762.)
10.19 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Peter J. Hill. (Incorporated by
reference to Exhibit 10.10 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)
10.20 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Steven W. Tholen. (Incorporated
by reference to Exhibit 10.11 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)
10.21 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Kerry R. Brittain. (Incorporated
by reference to Exhibit 10.12 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)
10.22 Employment Agreement dated August 1, 2002 between Harvest
Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by
reference to Exhibit 10.13 to our Form 10-Q filed on
November 8, 2002, File No. 1-10762.)
21.1 List of subsidiaries.
23.1 Consent of PricewaterhouseCoopers LLP. - Houston
23.2 Consent of Huddleston & Co., Inc.ZAO PricewaterhouseCoopers - Moscow
23.3 Consent of Ryder Scott Company, L.P.
99.1 Accompanying Certificates