UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
FORM 10-K
(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
COMMISSION FILE NO.
(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, 2003 | ||||
| or | ||||
| [] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||
Commission File No.: 1-10762
HARVEST NATURAL RESOURCES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
| Delaware | 77-0196707 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |
| 15835 | ||
| Houston, Texas | 77084 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code code:(281) 579-6700
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of each exchange on which registered | |
| Common Stock, $.01 Par Value | NYSE |
Securities registered pursuant to Section 12(g) of the Act:
| Title of each class | Name of each exchange on which registered | |
| None | None |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X[X] No ----------- ----------
[ ]
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'sregistrant’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[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'sregistrant’s most recently completed second fiscal quarter, June 28, 2002: $174,945,360.
27, 2003: $225,487,430.
Indicate the number of shares outstanding of each of the registrant'sregistrant’s classes of common stock, as of the latest practical date. Class: Common Stock, par value $0.01 per share, on March 21, 2003,1, 2004, shares outstanding: 35,216,211.
35,778,161.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant'sregistrant’s Proxy Statement for the 20032004 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of itsthe registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10, 11, 12, 13 and 1314 of Part III of this annual report.
HARVEST NATURAL RESOURCES, INC.
FORM 10-K
HARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
| Page | ||||||
| Part I | ||||||
| Item 1. | Business | 2 | ||||
| Item 2. | Properties | 14 | ||||
| Item 3. | Legal Proceedings | 14 | ||||
| Item 4. | Submission of Matters to a Vote of Security Holders | 14 | ||||
| Part II | ||||||
| Item 5. | Market for Registrant’s Common Equity and Related Stockholder Matters | 15 | ||||
| Item 6. | Selected Financial | 15 | ||||
| Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations | 16 | ||||
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 28 | ||||
| Item 8. | Financial Statements and Supplementary Data | 29 | ||||
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 29 | ||||
| Item 9A. | Controls and Procedures | 29 | ||||
| Part III | ||||||
| Item 10. | Directors and Executive Officers of the Registrant | 30 | ||||
| Item 11. | Executive Compensation | 30 | ||||
| Item 12. | Security Ownership of Certain Beneficial Owners and Management | 30 | ||||
| Item 13. | Certain Relationships and Related Transactions | 30 | ||||
| Item 14. | Principal Accounting Fees and Services | 30 | ||||
| Part IV | ||||||
| Item 15. | Exhibits, Financial Statement Schedules and Reports on Form 8-K | 31 | ||||
| Financial Statements | S-1 | |||||
| Signatures | S-35 | |||||
1
PART I
Harvest Natural Resources, Inc. ("Harvest"(“Harvest” or the "Company"“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"“budget”, "anticipate"“anticipate”, "expect"“expect”, "believes"“believes”, "goals"“goals”, "projects"“projects”, "plans"“plans”, "anticipates"“anticipates”, "estimates"“estimates”, "should"“should”, "could"“could”, "assume"“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, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include our substantialthe concentration of our operations in Venezuela, the political and economic risks associated with international operations, the anticipated future development costs for our undeveloped proved reserves, the risk that actual results may vary considerably from reserve estimates, the dependence upon the abilities and continued participation of certain of our key employees, the risks normally incident to the operation and development of oil and gas properties and the drilling of oil and natural gas wells, the availability of materials and supplies necessary to projects and operations, the price for oil and natural gas and related financial derivatives, changes in interest rates, basis risk and counterparty credit risk in executing commodity price risk management activities, the Company'sCompany’s ability to acquire oil and gas 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 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– 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 BUSINESS
GENERAL
Item 1. Business
General
Harvest Natural Resources, Inc. is an independent energy company engaged in the acquisition, development, production and productiondisposition of oil and gas properties since 1989, when it was incorporated under Delaware law. WeOver our history, we have acquired and developed significant interests in the Bolivarian Republic of Venezuela ("Venezuela"(“Venezuela”) and the Russian Federation ("Russia"(“Russia”) through our equity affiliate, and have undeveloped acreage offshore China. Our producing operations are conducted principally through our 80 percent-owned Venezuelan subsidiary, Benton-Vinccler, C.A. ("Benton-Vinccler"(“Benton-Vinccler”), which operates the South Monagas Unit in Venezuela; and
Limited Liability Company Geoilbent ("Geoilbent"), a Russian company of which we
own 34 percent and which operates the North Gubkinskoye and South Tarasovskoye
Fields in West Siberia, Russia. On February 27, 2002, we entered into a Sale and
Purchase Agreement to sell our entire 68 percent interest in Arctic Gas Company
("Arctic 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 (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).Venezuela. 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"’s (“PDVSA”) inability to accept our oil due to the national civil work stoppage in Venezuela. InWhile restoring production led to increased workover activity and higher operating costs, the return performance of the field was within our expectations. On November 25, 2003, we encountered
problems with somediversified our revenue stream by beginning the sale of natural gas in Venezuela. On September 25, 2003, we closed the Sale and Purchase Agreement to sell our wells, but we do not believe the associated costs will
be material. By the endentire 34 percent minority equity investment in LLC Geoilbent (“Geoilbent”), to Yukos Operational Holding Limited, a Russian oil and gas company, for $69.5 million plus $5.5 million as repayment 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.intercompany loans and outstanding accounts payable owed to us by Geoilbent. SeeItem 7 - Management's– Management’s Discussion and Analysis of Financial Conditions and Results of Operationsfor a complete description of these and other events.
As of December 31, 2002,2003, we had total estimated proved reserves,Proved Reserves in the South Monagas Unit, net of minority interest, and including our share of equity affiliates, of 127.3 MMBOE,96.4 MMBoe, and a standardized measure of discounted future net cash flow, before income taxes, for total proved reservesProved Reserves of $526.7$545.3 million. Of these totals, our
interests in the South Monagas Unit represented 102.5 MMBOE and $481.3 million,
and our equity interest in Geoilbent represented 24.8 MMBbls and $45.4 million,
respectively.
As of December 31, 2002,2003, we had total assets of $335.2$374.3 million. We had cash in excess of long term debt in the amount of $41.9 million. For the year ended December 31, 2003, we had total revenues of $106.1 million, net cash provided by operating activities of $38.5 million, and long-term debt of $96.8 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
For the year ended December 31, 2001, we had total revenues of
$122.4 million, net cash provided by operating activities of $36.6 million, and
long-term debt of $221.6 million.
AVAILABLE INFORMATION
2
Available Information
We file annual, quarterly and current reports, proxy statements and other documents with the SECSecurities and Exchange Commission (“SEC”) under the Securities Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC'sSEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. The public may obtain information on the operation of the 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,us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.
We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Current Reports on Form 3, 4 and 5, 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 addition, the Company haswe have adopted a codeCode of ethicsBusiness Conduct and Ethics that applies to all of itsour employees, including itsour chief executive officer, principal financial officer and principleprincipal accounting officer. The text of the codeCode of ethicsBusiness Conduct and Ethics has been posted on the Governance section of our website. We intend to post on our website any amendments to, or waivers from, our Code of Business Conduct and Ethics applicable to our senior officers. Additionally, the Company's
website.
OPERATING STRATEGYCode of Business Conduct and Ethics is available in print to any person who requests the information. Individuals wishing to obtain this printed material should submit a request to Harvest Natural Resources, Inc., attention Investor Relations.
Business Strategy
Our business strategy supports the steady investment, prudent risk
managementis to identify, acquire, develop and timely developmentproduce large discovered oil and gas fields in areas that are being largely avoided by many other oil and gas companies due to challenging political and economic circumstances. We have more than ten years of our large hydrocarbon resources. For the
foreseeable future, we believe our best success will be foundexperience in Venezuela and Russia, areas in which weand have significant experience and expertise. Near term,
our strategy is focused on improving the realization of value from our current
operationsestablished operating organizations in both Venezuelacountries. We seek additional opportunities in these two countries and Russia. Investments in Venezuelaother countries that meet our investment criteria. In executing our business strategy, we will strive to sustain the current balance sheet strength through financial prudence and rigorous investment profitability criteria; maximize cash flows from existing operations to invest in new opportunities; use our experience, skills and cash on hand to acquire new projects in Russia are
exposed to significant political risks.and Venezuela; and keep our organizational capabilities in line with our rate of growth.
In Venezuela, we intend to continue to seek cost effective increases in
production to extenddeliver more operating cash flow through the life and valueefficient management of our fields. Completing acapital expenditure programs and cost structure. We completed the first phase of our gas project at the South Monagas Unit in the fourth quarter ofNovember 2003 on time and within budget and commenced gas sales on November 25, 2003. This is an important partmilestone of thisour strategy because it creates a new sourcediversifies our revenues and cash flow, and develops vital market outlets to support further development of revenues from salesuntapped reserves of natural gas.gas in Eastern Venezuela. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures. We expect to reinvest this cash in new growth opportunities in Venezuela. In November 2003, we executed a Memorandum of Understanding with PDVSA to submit a plan of development for the previously developed Temblador Field and the discovered, yet undeveloped, El Salto Field. Under the terms of the Memorandum of Understanding, we can submit a plan of development for development of the fields under Venezuela’s Organic Hydrocarbon Law. We are also lookingin discussions with PDVSA for waysthe development of the nearby Isleno Field.
We are seeking to diversify our cash flow outside of Venezuela as events in Venezuelathere demonstrated the benefits of country risk diversificationrisks of our cash flow
sourcesconcentration in Venezuela when we lost six weeks of production.
Our Russian operations are an important elementproduction in the first part of our diversification
strategy.2003. We seek operational and the majority share owner in Geoilbentfinancial control, good minority interest partners, access to competitive oil and gas markets, and where possible, reliable export facilities and infrastructure. We seek low entry cost projects that need additional funding, execution skills and well reasoned development.
In Russia, we continue to striveevaluate a number of options to improve operations and monetize the value of the fields by lowering operating
costs and enhancing financial results. The Geoilbent assets represent
significant potential value for us, butinvest in known discoveries which remain subject to sub-optimal operating
conditions whileundeveloped or under-developed. In September 2003, we sold our lack of majority control over its operations inhibits34 percent minority equity investment in our ability to implement necessary changes in management, operations or financing
matters to fully realize the potential of Geoilbent's assets. In addition,Russian company Geoilbent. As a minority interest owner, 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 ourcontinuing investment in Geoilbent by improving its operations, achieving a control position or sellingwas determined to be inconsistent with our minority ownership interest.
We believe that Russia has opportunitiesobjective of investing in properties in which we have operating 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 partnership with local industry partners.
These partners must understand and be familiar with the asset and 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 that can be developed at low overall finding costs,
produced at low operating costs and converted into proved reserves, production
and value. We Manage Risk by controlling or mitigating the many factors within
our
3
control, such as continuing to improve our operating risks, access to markets
and financing flexibility. We Value Harvest our existing assets by rapid
development to convert underdeveloped hydrocarbons into cash.financial control.
We intend to continue to seekidentify, acquire and exploit newknown oil and natural gas reservesfields in our current areas of interestactivity while working toward minimizing the
associatedmaintaining our financial strength and operating risks.flexibility. 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: Weaccomplish this, we intend to focus our
activities only in areas of large known 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.to:
3
| • | Focus Our Efforts in Areas of Low Geologic Risk.We intend to focus our activities principally in areas of large known but undeveloped or under-developed oil and gas resources. | |||
| • | Seek operational and financial control. We desire to control all major decisions for development, production, staffing and financing of each project for a period of time sufficient for us to reap attractive returns on investments. | |||
| • | 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 partners in an effort to reduce our risk in any one venture. | |||
| • | Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to 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 under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash outlay. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure. | |||
| • | Limit Exploration Activities:We do not engage in exploration except in connection with the expansion of an existing reservoir and in that case only where the risks are deemed to be manageable in the context of total cash exposure and probability of success. | |||
| • | Maintain a prudent financial plan: We intend to maintain our financial flexibility by maintaining our total debt within average industry debt to capitalization levels, closely monitoring spending, holding significant cash reserves, actively seeking opportunities to reduce our weighted average cost of capital and increasing our liquidity. | |||
Our ability to successfully execute our strategy is subject to significant risks including, among other things, operating risks, political risks, legal risks and financial risks. Operating risks include our ability to 1) maintain
optimal production, 2) achieve maximum reserve recoverySeeItem 7 – Management’s Discussion and 3) maintain our cost
structure on an economically favorable basis, particularlyAnalysis of Financial Conditions and Results of Operationsand other information set forth elsewhere in Geoilbent in which
we arethis Form 10-K for a minority owner. Political risks in Venezuela are significant,description of these 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.
OPERATIONSother risk factors.
Operations
The following table summarizes our proved reserves,Proved Reserves, drilling and production activity, and financial operating data by principal geographic area at the end of each of the three years ending December 31, 2002.2003, 2002 and 2001. 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. We disposed of our Russian investments partly in 2002 and partly in 2003. Geoilbent and Arctic Gas arewere accounted for under the equity method and have beenwere included at their respective ownership interests in our consolidated financial statements.statements for the periods in which we owned such investments. 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, 2003, 2002 2001 and 20002001 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 2001 and 2000,2001, and from Arctic Gas, until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001 and
2000.2001.
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 2012. 4
We
BENTON-VINCCLER
--------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------
2002 2001 2000
---------- ---------- ----------
(DOLLARS IN 000's)
RESERVE INFORMATION
Proved reserves (MBOE) 102,534 83,611 98,431
Discounted future net cash flow attributable to proved
reserves, before income taxes $ 481,284 $ 176,210 $ 368,464
Standardized measure of future net cash flows $ 317,799 $ 163,328 $ 284,549
DRILLING AND PRODUCTION ACTIVITY:
Gross wells drilled 13 8 26
Average daily production (Bbls) 26,598 26,788 25,585
FINANCIAL DATA:
Oil revenues $ 126,731 $ 122,386 $ 139,890
Expenses:
Operating expenses and taxes other than on income 31,608 42,175 46,848
Depletion 22,685 21,175 15,708
Income tax expense 4,866 9,083 20,307
---------- ---------- ----------
Total expenses 59,159 72,433 82,863
---------- ---------- ----------
Results of operations from oil and natural gas
producing activities $ 67,572 $ 49,953 $ 57,027
========== ========== ==========
ownhave submitted a request for extension under the force majeure provisions of our contract. The Venezuelan national civil work stoppage required Benton-Vinccler to shut-in production for approximately two months. We believe the two months representing this delay will be added to the original term of our agreement.
4
| Benton-Vinccler | ||||||||||||
| Year Ended December 31, | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| (Dollars in 000’s) | ||||||||||||
RESERVE INFORMATION | ||||||||||||
| Proved Reserves (MBoe) | 96,364 | 102,534 | 83,611 | |||||||||
| Discounted future net cash flow attributable to proved reserves, before income taxes | $ | 545,308 | $ | 481,284 | $ | 176,210 | ||||||
| Standardized measure of future net cash flows | $ | 366,770 | $ | 317,799 | $ | 163,328 | ||||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||||||
| Gross wells drilled | 3 | 13 | 8 | |||||||||
| Average daily production (Boe) | 20,130 | 26,598 | 26,788 | |||||||||
FINANCIAL DATA: | ||||||||||||
| Oil and natural gas revenues | $ | 106,095 | $ | 126,731 | $ | 122,386 | ||||||
| Expenses: | ||||||||||||
| Operating expenses and taxes other than on income | 31,445 | 31,608 | 42,175 | |||||||||
| Depletion | 19,599 | 22,685 | 21,175 | |||||||||
| Income tax expense | 12,158 | 4,866 | 9,083 | |||||||||
| Total expenses | 63,202 | 59,159 | 72,433 | |||||||||
| Results of operations from oil and natural gas producing activities | $ | 42,893 | $ | 67,572 | $ | 49,953 | ||||||
We owned 34 percent of Geoilbent, which we accountaccounted 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 and 2000.
| Geoilbent | ||||||||||||
| Year Ended September 30, | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| (Dollars in 000’s) | ||||||||||||
RESERVE INFORMATION | ||||||||||||
| Proved Reserves (MBbls) | (a | ) | 25,356 | 29,668 | ||||||||
| Discounted future net cash flow attributable to proved reserves, before income taxes | (a | ) | $ | 117,229 | $ | 81,125 | ||||||
| Standardized measure of future net cash flows | (a | ) | $ | 92,939 | $ | 70,648 | ||||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||||||
| Gross development wells drilled | (a | ) | 6 | 39 | ||||||||
| Net development wells drilled | (a | ) | 2 | 13 | ||||||||
| Average daily production (Bbls) | 5,242 | 6,438 | 4,830 | |||||||||
FINANCIAL DATA: | ||||||||||||
| Oil and natural gas revenues | $ | 27,876 | $ | 31,039 | $ | 34,261 | ||||||
| Expenses: | ||||||||||||
| Operating, selling and distribution expenses and taxes other than on income | 16,088 | 16,902 | 16,083 | |||||||||
| Depletion | 6,215 | 9,237 | 5,072 | |||||||||
| Write-down of oil and gas properties | 32,300 | — | — | |||||||||
| Income tax expense | 2,073 | 1,955 | 3,742 | |||||||||
| Total expenses | 56,676 | 28,094 | 24,897 | |||||||||
| Results of operations from oil and natural gas producing activities | $ | (28,800 | ) | $ | 2,945 | $ | 9,364 | |||||
| (a) | Geoilbent was sold on September 25, 2003. |
As of December 31, 2001, we owned, free of any sale and 2000.
5
ARCTIC GAS COMPANY
--------------------------------------
YEAR ENDED SEPTEMBER 30,
--------------------------------------
2002 2001 2000
---------- ---------- ----------
(DOLLARS IN 000's)
RESERVE INFORMATION
Proved reserves (MBOE) (a) 55,631 41,236
Discounted future net cash flow attributable to proved
reserves, before income taxes (a) $ 108,400 $ 74,517
Standardized measure of future net cash flows (a) $ 82,205 $ 56,880
DRILLING AND PRODUCTION ACTIVITY:
Gross wells reactivated (a) 2 4
Average daily production (BOE) 189 502 134
FINANCIAL DATA:
Oil and natural gas revenues $ 3,554 $ 4,016 $ 889
Expenses:
Selling and distribution expenses 1,429 1,165 --
Operating expenses and taxes other than on income 1,673 2,215 604
Depletion 139 311 78
---------- ---------- ----------
Total expenses 3,241 3,691 682
---------- ---------- ----------
Results of operations from oil and natural gas
producing activities $ 313 $ 325 $ 207
========== ========== ==========
(a)transfer restrictions, 39 percent of the equity interests in Arctic Gas, which we accounted 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, 2001),
5
drilling and production activity, and financial operating data for the period until it was sold on April 12, 2002 SOUTH MONAGAS UNIT, VENEZUELA (BENTON-VINCCLER)
and for the twelve months ended September 30, 2001.
| Arctic Gas Company | ||||||||
| Year Ended September 30, | ||||||||
| 2002 | 2001 | |||||||
| (Dollars in 000’s) | ||||||||
RESERVE INFORMATION | ||||||||
| Proved Reserves (MBoe) | (a | ) | 55,631 | |||||
| Discounted future net cash flow attributable to proved reserves, before income taxes | (a | ) | $ | 108,400 | ||||
| Standardized measure of future net cash flows | (a | ) | $ | 82,205 | ||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||
| Gross wells reactivated | (a | ) | 2 | |||||
| Average daily production (Bbls) | 189 | 502 | ||||||
FINANCIAL DATA: | ||||||||
| Oil and natural gas revenues | $ | 3,554 | $ | 889 | ||||
| Expenses: | ||||||||
| Selling and distribution expenses | 1,429 | 1,166 | ||||||
| Operating expenses and taxes other than on income | 1,673 | 2,215 | ||||||
| Depletion | 139 | 311 | ||||||
| Income tax expense | 19 | 80 | ||||||
| Total expenses | 3,260 | 3,772 | ||||||
| Results of operations from oil and natural gas producing activities | $ | 294 | $ | (2,883 | ) | |||
| (a) | Arctic Gas was sold on April 12, 2002. |
South Monagas Unit, Venezuela (Benton-Vinccler)
General
In July 1992, we and Venezolana de Inversiones y Construcciones Clerico, C.A., a Venezuelan construction and engineering company ("Vinccler"(“Vinccler”), signed a 20-year operating service agreement with Lagoven, S.A., an affiliate of PDVSA, to reactivate and further develop the Uracoa, Tucupita and Bombal 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'sBenton-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
| • | mergers; | |||
| • | consolidations; | |||
| • | sales of substantially all of its corporate assets; | |||
| • | change of business; and | |||
| • | similar major corporate events. | |||
Vinccler has an extensive operating history in Venezuela. It provided Benton-Vinccler with initial financial assistance and significant construction services. Vinccler continues to provide ongoingprovided assistance with construction projects, governmental relations and labor relations.relations during 2003.
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
6
ownership of all hydrocarbons in the fields. In addition, PDVSA maintains full ownership of equipment and capital infrastructure following its installation.
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"(“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 January 2002, Benton-Vinccler installed 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 Benton-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 fourth 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 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 50began in November 2003 and were averaging 70-80 MMcf of natural gas per day inby the fourth quarterend of 2003 and gradually increase up to 70 MMcfpd in 12 to 18 months
from the initial sale.year. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production (“Incremental Crude Oil”). Incremental Crude Oil is sold at a price of $7.00 per barrel beginning with our firstthe quarterly volume of such sales based on quarterly natural gas sale.
Initialsales multiplied by the ratio of 4.5 MMBls to 198 Bcf.
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. At the end of each quarter, Benton-Vinccler also prepares invoices for natural gas production will come from Uracoa, which allows us to more
efficiently managesales and Incremental Crude Oil. Payment is due under the reservoir and eliminateinvoices by the restrictions on producing oil
wells with high gas to oil ratios. The gas reserves in Bombal will be used to
meet the future termsend of the second month after the end of the quarter. Invoice amounts and payments are denominated in U.S. dollars. Payments are wire transferred into Benton-Vinccler’s account in a commercial bank in the United States.
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 one percent water. Quality measurements are conducted both at Benton-Vinccler’s facilities and at PDVSA’s storage facility.
With respect to gas contract in 2005 or 2006.
Ansales, an initial capital investment of approximately $26$27 million will bewas 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 startcompleted the fabrication and construction process for the gas pipeline in earlylate 2003. Benton-Vinccler has borrowed $15.5 million under a project loan for the gas pipeline and related facilities and the remainder will bewas funded from existing cash balances and internally generated cash flow. In addition, Benton-Vinccler has entered into long-term agreements for the leasing of compression, and the operation and maintenance of the gas treatment and compression facilities. The operating services agreement contains requirements for the measurement and quality of the natural gas delivered to PDVSA.
In August 1999, Benton-Vinccler sold its power generation facility located in the Uracoa and Tucupita Fields. 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.
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 of the acreage. At December 31, 2002, proved reserves2003, Proved Reserves attributable to our Venezuelan operations were 128,168 MBOE (102,534 MBOE120,455 MBoe (96,364 MBoe net to Harvest). This represented approximately 80100 percent of our proved reservesProved Reserves at year end. Benton-Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 6266 percent of the South Monagas Unit's
proved reserves. Benton-Vinccler is currently reinjecting most of the associated
natural gas produced at Uracoa back into the reservoir.
Unit’s Proved Reserves.
7
Drilling and Development Activity
Benton-Vinccler drilled 11three oil wells and 2 waterconverted two gas injection wells to producing wells in 20022003 and had an average of 131111 wells on production in all fields in 2002.
7
URACOA FIELD2003.
Uracoa Field
Benton-Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field.
Benton-Vinccler processes the oil, water and natural gas produced from
the Uracoa Field in the Uracoa central processing unit. Benton-Vincclerunit and ships the processed oil via pipeline to the PDVSA custody transfer point. Benton-Vinccler treats and filters produced water, and then re-injectsreinjects it into the aquifer to assist the natural water drive. Benton-Vinccler re-injectshad reinjected produced natural gas into the natural gas cap primarily for storage conservation.conservation until November 2003, at which time it began selling the natural gas. 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 40 to 45injection capacity of 46 MMcf of natural gas per day. In August 1999, Benton-VincclerPresently all gas being sold its power generation facility
located inis produced from the Uracoa Field.
Tucupita Field
There are currently 31 oil producing wells and six water injection wells at Tucupita. The current production facility has capacity to handle 30 MBbls of oil per day, 125 MBbls of water per day and storage for $15.1 million. Concurrently with the sale,
Benton-Vinccler entered into a long-term power purchase agreement with the
purchaserup to 60 MBbls 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
In 2001, Benton-Vinccler reactivated nine wells in Tucupita and in 2002
completed eleven oil producers and two water injectors.crude oil. The oil is transported through a 31-mile, 20 MBbl per day capacity oil pipeline constructed in 2001 from Tucupita to the Uracoa central processing unit.
Benton-Vinccler is reinjectingreinjects 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 to supply our power needs.
To date, we have
Bombal Field
In 2003, Benton-Vinccler drilled one wellthree wells in the West Bombal Field. Portable separation, pumping and storage for 7.5 MBbl of crude oil are maintained at the field. The crude oil is pumped via a pipeline and tied into the 31-mile Tucupita oil pipeline to the Uracoa central processing unit. The East Bombal Field was drilled in 1992, and reactivated
another.
the wells were suspended until gas sales could take place. Benton-Vinccler expects to begin engineering and design studies in late 2004 with first gas sales expected in 2005. Gas from this field will be used to supplement gas production from Uracoa as production there declines.
Customers and Market Information
Under the operating service agreement, all oil and natural gas produced is delivered to PDVSA for an operatinga fee. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA'sPDVSA’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. 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. While we have substantial cash reserves, a prolonged loss of sales could have a material adverse effect on our financial condition.
Employees and Community Relations
Benton-Vinccler has a highly skilled staff of 172189 local employees and 5four expatriates and has also formed successful and supportive relationships with local government agencies and communities.
Benton-Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care, as well as additional social investments including the purchase of medicines and medical equipment infor local communities within the South Monagas Unit.
Health, Safety and Environment
Benton-Vinccler's
Benton-Vinccler’s health, safety and environmental policy is an integral part of its business. Annually, Benton-Vinccler continually improves its policy and practices related to personnel safety, property protection and
8
environmental management. These improvements can be directly attributed to theits 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. 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 Minley and
have not experienced any disagreements on major operational matters. We are
reviewing ways to improve the operations, but as a minority shareholder 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.
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, FieldsRussia (Geoilbent)
On September 25, 2003, we sold our 34 percent minority equity investment in the West Siberia region of Russia,
located approximately 2,000 miles northeast of Moscow. Large proved oil and gas
fields surround all four of Geoilbent's licenses.
The North Gubkinskoye 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 Jurassic 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 and natural gas
liquids.
The South Tarasovskoye Field is located southeast of North Gubkinskoye
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 Market 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 began operations in 1992, the North Gubkinskoye Field
was one of the largest non-producing oil and gas fields in the region. Geoilbent
transports 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 handles all export oil sales, which are paid
in US dollars into Geoilbent's bank account. In 2002, approximately 34% of
Geoilbent's production was sold in the world export market and 66% in the
domestic Russian market. Geoilbent'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 the winter export limitations.
Geoilbent is continuing to pursue its oil development program. The
current production facilities are operating at or near capacity and will need to
be expanded 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 the 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 development 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 meetYukos Operational Holding Limited for $69.5 million plus $5.5 million for 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 eventrepayment of default whereby EBRD may, at its option, demand
payment of the outstanding principalintercompany loans and interest. In addition, the restructured
loan agreement requires that Geoilbent implement 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 interest. For a more
complete description of the terms and conditions of the EBRD loan and
Geoilbent's covenant obligations,accounts receivable. See Item 7 - Risk Factors and Note 9 -– Russian Operations.
Employees, Community and Country Relations
Geoilbent employs six 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 resides in the area
of oilfield operations.
EAST URENGOY, RUSSIA (ARCTIC GAS COMPANY)
East Urengoy, Russia (Arctic Gas Company)
Arctic Gas Company was sold in April 2002. SeeNote 9 -– Russian Operations.
Operations.
WAB-21, SOUTH CHINA SEA (BENTON OFFSHORE CHINA COMPANY)
South China Sea (Benton Offshore China Company)
General
In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation ("CNOOC"(“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'sPeople’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same 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 under dispute. As part of oura review of Companyour assets, wea third-party conducted a third-partyan 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. An evaluation was performed again at December 31, 2003, and such evaluation indicated that no further impairment of the property had been incurred in 2003.
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'sPetroleum’s giant natural gas discovery at Lan Tay (Red Orchid) and 100 miles north of Exxon'sExxon’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 a license extension,extensions, with the current extension in effect until May 31, 2005.
DOMESTIC OPERATIONS
We had a 35 percent working interest in the Lakeside Exploration
Prospect, Cameron Parish, Louisiana. In September 2002, we determined the Claude
Boudreaux #1 exploratory well was not prospective for hydrocarbons and assigned
our entire interest in the Lakeside Exploration Prospect to a third party and
recognized a $1.1 million impairment.
Domestic Operations
We acquired a 100 percent interest in three California State offshore oil and gas leases ("(“the California Leases"Leases”) and a parcel of onshore property from Molino Energy Company, LLC. All capitalized costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the Company has issued the 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 AREAonshore property for sale.
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:
9
| Other | Total | |||||||||||||||||||
| (in thousands) | Venezuela | Foreign | Foreign | United States | Total | |||||||||||||||
Year ended December 31, 2003 | ||||||||||||||||||||
| Oil and gas sales | $ | 106,095 | $ | 106,095 | $ | 106,095 | ||||||||||||||
| Total Assets | $ | 241,855 | $ | 237 | $ | 242,092 | $ | 132,256 | $ | 374,348 | ||||||||||
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 | $ | 122,386 | $ | 122,386 | $ | 122,386 | ||||||||||||||
| Total Assets | $ | 167,671 | $ | 100,801 | $ | 268,472 | $ | 79,679 | $ | 348,151 | ||||||||||
Reserves
Estimates of our proved reservesProved Reserves as of December 31, 20022003 and 20012002 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. The following table sets forth information regarding estimates of proved reservesProved Reserves at December 31, 2002.2003. 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 there are substantial natural gas
reserves in the license blocks held by Geoilbent, no natural gas reserves have
been recorded as of December 31, 2002 because of a lack of sales and
transportation contracts in place.
11
NET CRUDE OIL AND CONDENSATE (MBbls)
--------------------------------------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
----------------- ------------------- ----------------
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)
--------------------------------------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
----------------- ------------------- ----------------
Venezuela........................................ 84,000 74,400 158,400
================= =================== ================
Net Crude Oil and Condensate (MBbls) Proved Proved Developed Undeveloped Total Venezuela 36,688 33,610 70,298
Net Natural Gas (MMcf) Proved Proved Developed Undeveloped Total Venezuela 84,918 71,482 156,400
Estimates of commercially recoverable oil and natural gas reserves and of the future net cash flows derived there fromtherefrom 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
| • | historical production from the subject properties; | |||
| • | comparison with other producing properties; | |||
| • | the assumed effects of regulation by governmental agencies; and | |||
| • | assumptions concerning future operating costs, municipal taxes, | |||
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 and natural gas 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 there from,therefrom, prepared by different engineers or by the same engineers at different times may vary substantially. The difficulty of making precise estimates is accentuated by the fact that 4647 percent of our total proved reservesProved Reserves were undeveloped as of December 31, 2002.2003. The following costs therefore will likely vary from our estimates and
such variances maycost to develop the Proved Undeveloped Reserves is expected to be material:
o severance and excise taxes;
o export tariffs;
o development expenditures;
o workover and remedial expenditures;
o abandonment expenditures; and
o operating expenditures.$65.6 million over the next three years.
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
10
| • | actual production; | |||
| • | oil and natural gas sales; | |||
| • | supply and demand for oil and natural gas; | |||
| • | availability and capacity of gathering systems and pipelines; | |||
| • | changes in governmental regulations or taxation; and | |||
| • | the impact of inflation on costs. | |||
The timing of actual future net oil and natural gas sales from proved
reservesProved 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 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, risks associated with the oil and natural gas industry and the political risks associated with operations in Venezuela and Russia.Venezuela. Discounted present value, regardless 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
2002,2003, we reported $526.7$545.3 million of discounted future net cash flows before income taxes from proved
reservesProved Reserves based on the SEC'sSEC’s required calculations.
PRODUCTION, PRICES AND LIFTING COST SUMMARY
Production, Prices and Lifting Cost Summary
In the following table we have set forth by country our net production, average sales prices and average operating expenses for the years ended December 31, 2003, 2002 2001 and 2000.2001. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership) and Arctic Gas (39 and 29 percent ownership not subject to any sale or transfer restrictions at December 2001 and 2000, respectively)2001), which are accounted for under the equity method, have been included at their respective ownership interest in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, our results of operations for the years ended December 31, 2003, 2002 2001 and 20002001 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 2001 and 2000,2001 and from Arctic Gas until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001 and 2000.
2001.
| Year Ended December 31, | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
Venezuela | ||||||||||||
| Crude Oil Production (Bbls) | 7,347,399 | 9,708,295 | 9,777,516 | |||||||||
| Natural Gas Production (MMcf) | 2,660,241 | — | — | |||||||||
| Average Crude Oil Sales Price ($per Bbl) | $ | 14.07 | $ | 13.08 | $ | 12.52 | ||||||
| Average Natural Gas Sales Price ($per MMcf) | $ | 1.03 | — | — | ||||||||
| Average Operating Expenses ($per Boe) | $ | 4.00 | $ | 3.26 | $ | 4.30 | ||||||
Russia | ||||||||||||
Geoilbent (a)(b) | ||||||||||||
| Net Crude Oil Production (Bbls) | 1,913,187 | 2,349,916 | 1,762,814 | |||||||||
| Average Crude Oil Sales price ($per Bbl) | $ | 14.52 | $ | 13.21 | $ | 19.51 | ||||||
| Average Operating Expenses ($per Bbl) | $ | 2.83 | $ | 2.09 | $ | 2.17 | ||||||
Arctic Gas (a)(c) | ||||||||||||
| Net Crude Oil Production (Bbls) | (c | ) | (c | ) | 183,087 | |||||||
| Average Crude Oil Sales price ($per Bbl) | (c | ) | (c | ) | $ | 21.93 | ||||||
| Average Operating Expenses ($per Bbl) | (c | ) | (c | ) | $ | 7.42 | ||||||
| (a) | Information represents our ownership interest. | |||
| (b) | Geoilbent was sold on September 25, 2003. | |||
| (c) | Arctic Gas was sold on April 12, 2002. | |||
11
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
| • | change in governments; | |||
| • | civil unrest; | |||
| • | price and currency controls; | |||
| • | limitations on oil and natural gas production; | |||
| • | world demand for crude oil; | |||
| • | tax, environmental, safety and other laws relating to the petroleum industry; | |||
| • | changes in such laws; and | |||
| • | changes in administrative regulations and the interpretation and application of such rules and regulations. | |||
In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.
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 Venezuelan Bolivar and the U.S. dollar and restrict the ability to exchange Venezuelan Bolivars for U.S. dollars and vice versa. Initially the exchange rate was set at 1,600 Venezuelan Bolivars for each U.S. dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar. Oil companies such as Benton-Vinccler are allowed to receive payments for oil sales in U.S. currencydollars and pay U.S. dollar-denominated debt, dividends and expenses from those payments. We are unable to predict the impact
ofdo not expect the currency controlsconversion restrictions or the adjustment in the exchange rate to have a material impact 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.at this time.
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 budgets to PDVSA for approval including capital expenditures to comply with Venezuelan environmental regulations. No capital expenditures to comply with environmental regulations were required in 2002.2002 or 2003. 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 towith the national tax administration and towith various municipalities.
Russia
Geoilbent submits annual production
Drilling and development plans, which
include information necessary for permits and approvals for its 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.
Geoilbent submits annual production targets and quarterly export nominations for
oil pipeline transportation capacity to the Ministry of Fuel and Energy.
Geoilbent is 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 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 government sets the maximum crude oil export tariff rate
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 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 on Geoilbent's operations.
14
DRILLING AND UNDEVELOPED ACREAGEUndeveloped 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 $58.3 million, during 2002;
o $44$50.6 million during 2001; and o $50$43.9 million during 2000;in 2003, 2002 and 2001, respectively. Included in these numbers is $43.6 million, $44.3 million and $28.0 million for the development of Proved Undeveloped Reserves in 2003, 2002 and 2001, respectively.
We have drilled or participated through our equity affiliate in the drilling of wells as follows:
12
| Year Ended December 31, | ||||||||||||||||||||||||
| 2003 | 2002 | 2001 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Wells Drilled: | ||||||||||||||||||||||||
| Exploration: | ||||||||||||||||||||||||
| Dry hole | — | — | 1 | 0.4 | — | — | ||||||||||||||||||
| Development: | ||||||||||||||||||||||||
| Crude oil | 3 | 2.4 | 17 | 10.8 | 20 | 10.5 | ||||||||||||||||||
| Total | 3 | 2.4 | 18 | 11.2 | 20 | 10.5 | ||||||||||||||||||
Average Depth of Wells (Feet) | 6,095 | 7,341 | 6,043 | |||||||||||||||||||||
Producing Wells(1): | ||||||||||||||||||||||||
| Crude Oil | 111 | 88.8 | 258 | 158.2 | 274 | 169.9 | ||||||||||||||||||
| (1) | The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired. |
All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.
ACREAGE
Acreage
The following table summarizes the developed and undeveloped acreage that we owned, leased or held under operating service agreement or concession as of December 31, 2002:
| Developed | Undeveloped | |||||||||||||||
| Gross | Net | Gross | Net | |||||||||||||
| Venezuela | 11,166 | 8,933 | 146,677 | 117,342 | ||||||||||||
| China | — | — | 7,470,080 | 7,470,080 | ||||||||||||
| Total | 11,166 | 8,933 | 7,616,757 | 7,587,422 | ||||||||||||
Competition
We encounter strong competition from major oil and gas companies and independent operators in acquiring properties and leases for the exploration forand development of crude oil and natural gas. The principal competitive factors in the acquisition of such oil and gas properties include political, staff and data necessary to identify, investigate and purchase such leases,properties, and the financial resources necessary to acquire and develop such leases.properties. Many of our competitors have financial resources, staffs, data resources and facilities substantially greater than ours.
15
ENVIRONMENTAL REGULATION
Environmental Regulation
Various federal, state, local and international laws and regulations relating to 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. 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
Employees
At December 31, 2002,2003, we had 1918 full-time employees, augmented from time-to-timetime to time with independent consultants, as required. Benton-Vinccler had 172189 employees and Geoilbentour Moscow office had 700 local14 employees.
TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE
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 other 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.
13
The WAB-21 petroleum contract lies within an area which is the subject of a territorial dispute between the People'sPeople’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with 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.
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.
Bbl. "Bbl" means barrel. "Bbls" means barrels. "MBbls" means thousand barrels.
"MMBbls" means million barrels.
BOE. "BOE" means barrels of oil equivalent, which are determined using the ratio
of one barrel of crude oil, condensate or natural gas liquids to six Mcf of
natural gas so that six Mcf of natural gas is referred to as one barrel of oil
equivalent or "BOE". "MBOE" means thousands of barrels of oil equivalent.
"MMBOE" means millions of barrels of oil equivalent.
CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with
exploratory and development drilling (including exploratory dry holes);
leasehold acquisitions; seismic data acquisitions; geological, geophysical and
land-related overhead expenditures; delay rentals; producing property
acquisitions; and other miscellaneous capital expenditures.
COMPLETION COSTS. "Completion Costs" means, as to any well, all those costs
incurred after the decision to complete the well as a producing well. Generally,
these costs include all costs, liabilities and expenses, whether tangible or
intangible, necessary to complete a well and bring it into production, including
installation of service equipment, tanks, and other materials necessary to
enable the well to deliver production.
DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional well
to the same reservoir as other producing wells on a lease, or drilled on an
offset lease not more than one location away from a well producing from the same
reservoir.
EXPLORATORY WELL. An "Exploratory Well" is a well drilled in search of a new and
as yet undiscovered pool of oil or natural gas, or to extend the known limits of
a field under development.
FINDING COST. "Finding Cost", expressed in dollars per BOE, is calculated by
dividing the amount of total capital expenditures related to acquisitions,
exploration and development costs (reduced by proceeds for any sale of oil and
gas properties) by the amount of total net reserves added or reduced as a result
of property acquisitions and sales, drilling activities and reserve revisions
during the same period.
FUTURE DEVELOPMENT COST. "Future Development Cost" of proved nonproducing
reserves, expressed in dollars per BOE, is calculated by dividing the amount of
future capital expenditures related to development properties by the amount of
total proved non-producing reserves associated with such activities.
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.
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.
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.
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" are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known oil and natural gas reservoirs under existing economic and operating
conditions, that is, on the basis of prices and costs as of the date the
estimate is made and any price changes provided for by existing conditions.
PROVED UNDEVELOPED RESERVES. "Proved Undeveloped Reserves" are Proved Reserves
which can be expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is required for
recompletion.
RESERVES. "Reserves" means crude oil and natural gas, condensate and natural gas
liquids, which are net of leasehold burdens, are stated on a net revenue
interest basis, and are found to be commercially recoverable.
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS. The "Standardized Measure of
Future Net Cash Flows" is a method of determining the present value of Proved
Reserves. The future net oil sales from Proved Reserves are estimated assuming
that oil and natural gas prices and production costs remain constant. The
resulting stream of oil sales is then discounted at the rate of 10 percent per
year to obtain a present value.
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 acreage contains proved
reserves.
ITEM
Item 2. PROPERTIESProperties
In July 2001, we leased 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;2004. We have subleased all of thisthe office space has been subleasedin California for rents that approximate our lease costs.
ITEM
Item 3. LEGAL PROCEEDINGS
See Note 13 -Legal Proceedings
Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas. This suit was brought in May, 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. The Court has abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. We dispute Excel’s claims and plan to vigorously defend against them.
Item 4. Submission of Matters to a Vote of Security Holders
None.
14
PART II
Item 5. Market for Registrant’s Common Equity and Related Party Transactions regarding the A. E. Benton proceeding.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Stockholder Matters
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our Common Stock hasis traded on the New York Stock Exchange ("NYSE"(“NYSE”) since May
20, 2002 under the symbol "HNR". Prior to that date it traded under the symbol
"BNO"“HNR”. As of December 31, 2002,2003, there were 35,248,29635,674,660 shares of common stock outstanding, with approximately 866808 stockholders of record. The following table sets forth the high and low sales prices for our Common Stock reported by the NYSE.
| Year | Quarter | High | Low | |||||||
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 | ||||||||
2003 | ||||||||||
| First quarter | 6.58 | 4.40 | ||||||||
| Second quarter | 6.90 | 4.20 | ||||||||
| Third quarter | 7.17 | 5.58 | ||||||||
| Fourth quarter | 10.02 | 6.35 | ||||||||
On March 21, 2003,1, 2004, the last sales price for the common stock as reported by the NYSE was $4.40$11.68 per share.
Our policy is to retain earnings to support the growth of our business. Accordingly, our Boardboard of Directorsdirectors has never declared a cash dividend on our common stock and our indenture currently restricts the declaration and payment of any cash dividends.
19
ITEM
Item 6. SELECTED FINANCIAL DATA
Selected 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, 2002.2003. 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, 2003, 2002, 2001, 2000 1999 and 19981999 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2002, 2001, 2000 1999 and 1998,1999, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2002, 2001, 2000 1999 and 1998.
1999.
15
| Year Ended December 31, | ||||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| (in thousands, except per share data) | ||||||||||||||||||||
Statement of Operations: | ||||||||||||||||||||
| Total revenues | $ | 106,095 | $ | 126,731 | $ | 122,386 | $ | 140,284 | $ | 89,060 | ||||||||||
| Operating income (loss) | 33,627 | 34,585 | 28,201 | 53,204 | (22,525 | ) | ||||||||||||||
| Net income (loss) | 27,303 | 100,362 | 43,237 | 20,488 | (32,284 | ) | ||||||||||||||
| Net income (loss) per common share: | ||||||||||||||||||||
| Basic | $ | 0.77 | $ | 2.90 | $ | 1.27 | $ | 0.67 | $ | (1.09 | ) | |||||||||
| Diluted | $ | 0.74 | $ | 2.78 | $ | 1.27 | $ | 0.66 | $ | (1.09 | ) | |||||||||
| Weighted average common shares outstanding Basic | 35,332 | 34,637 | 33,937 | 30,724 | 29,577 | |||||||||||||||
| Diluted | 36,840 | 36,130 | 34,008 | 30,890 | 29,577 | |||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||
| Working capital (deficit) | $ | 137,210 | $ | 97,001 | $ | (586 | ) | $ | 12,370 | $ | 32,093 | |||||||||
| Total assets | 374,348 | 335,192 | 348,151 | 286,447 | 276,311 | |||||||||||||||
| Long-term debt, net of current maturities | 96,833 | 104,700 | 221,583 | 213,000 | 264,575 | |||||||||||||||
Stockholders’ equity (deficit)(1) | 199,713 | 171,317 | 67,623 | 12,904 | (17,178 | ) | ||||||||||||||
| (1) | No cash dividends were declared or paid during the periods presented. |
| Item 7. | Management’s Discussion and Analysis of |
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.
OUR CONCENTRATION OF ASSETS IN VENEZUELA INCREASES OUR EXPOSURE TO PRODUCTION
DECLINES AND DISRUPTIONS. During 2002,us.
Our concentration of assets in Venezuela increases our exposure to production disruptions and project execution risk.Political and economic uncertainty is very high in Venezuela. Currently, the production from the South Monagas Unit in Venezuela representedrepresents all of our total production, from consolidated
companies. Our production,and 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'sPDVSA’s inability to accept our oil due to the national civil work stoppage in Venezuela. As a result, 2002 sales were reduced by approximately 550,0000.6 million barrels and 2003 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 Venezuelan national civil work stoppage, the Government of VenezuelaVenezuelan government terminated several thousand PDVSA employees and announced a decentralizationrestructuring of PDVSA'sPDVSA’s operations. WhileThroughout 2003, there have been numerous organizational changes in PDVSA. As a result of the situation in PDVSA, its payment to Benton-Vinccler for crude oil delivered in the fourth quarter of 2002 was late by seven days. However, all other payments have been on time, and we believe PDVSA is committed to building its production levels and returning to more normalized business relations with its customers and suppliers.
There are ongoing efforts by opponents of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of thesethe changes and the possible politicalization of PDVSA cannot be predicted, it could adversely affect PDVSA'sPDVSA’s ability to manage its contracts and meet its obligations with its suppliers and vendors, such as Benton-Vinccler. As a resultOrganizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing 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.those acquisitions. While we have substantial cash reserves to withstand a future
16
disruption of sales, 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 been required to curtail sales to PDVSA in April and December 2002 due to insufficient crude oil storage capacity. We have never been requiredWhile these appear to curtail sales before 2002. Webe isolated incidents, we cannot be assured that our sales to PDVSA will not be curtailed in the future in the same manner.
GEOILBENT'S LIQUIDITY COULD LIMIT ITS ABILITY TO MAINTAIN OR INCREASE
PRODUCTION.
ABILITY TO COMPLY WITH CREDIT FACILITY.
Our strategy to focus on Russia carries operating, financial, legal and political risk.While we believe our established presence in Russia and our experience and skills from prior operations positions us well for future projects, doing business in Russia also carries unique risks. The $50 million revolving credit
agreementoperating environment is often difficult, and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, apply “best practices” in drilling and development, and the fostering of relationships with EBRD requires that Geoilbent meet certain covenants whichRussian partners, the local community and governmental authorities. Financial risks include among other things,our ability to control costs and attract financing for Russian projects, while remaining within our existing debt covenants. In addition, the maintenance of financial ratios. If Geoilbent
failsRussian legal system is not mature and its reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and gas projects, as well as our ability to obtain adequate compensation for any resulting losses.
Acquiring new projects in Venezuela depends upon our ability 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 interest. In addition,Organic Hydrocarbon Law.New oil projects in Venezuela are governed by the loan agreementOrganic Hydrocarbon Law which requires that Geoilbent implementsuch projects be carried out through incorporated joint ventures with majority ownership by governmental entities. While we believe it is possible to comply with the Organic Hydrocarbons Law and at the same time meet our criteria for new projects, no precedents exist and there is a new management information system by May 1, 2003. If
Geoilbent isrisk we will be unable to timely satisfy this requirement, it also resultsachieve the desired result.
Operations in an
event of default whereby EBRD may, at its option, demand payment ofareas outside the outstanding principalU.S. are subject to various risks inherent in foreign operations, and interest. Any event of default also gives EBRD the
rightour strategy to exercise its security interest in the assets of Geoilbentfocus on Venezuela and under a
share pledge agreement,Russia limits our ownership interest in Geoilbent. An event of default
could also limit Geoilbent's ability to access additional funds under the EBRD
facility. It is unlikely that Geoilbent 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 meet its current liabilities, there can be no assurance that
Geoilbent will be able to meet the current ratio requirement on March 31, 2003.
As a result of these 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 and continue as a going concern. 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.
ABILITY TO REPAY ACCOUNTS PAYABLE. At September 30, 2002, and September 30,
2001, the current liabilities of Geoilbent exceeded its current assets by $35.3
million and $25.0 million, respectively. 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, 2002, Geoilbent had accounts payable outstanding of
$12.2 million of which approximately $5.9 million was 90 days or more past due.
The amounts outstanding were primarily to contractors and vendors for drilling
and construction services. Under 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 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. Should oil prices
decline for a prolonged period, or if Geoilbent is unable to access the EBRD
facility or the shareholders are unwilling to make capital contributions, then
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. Although the Company may consider making a capital contribution,
there can be no assurances that the Company will do so, nor can there be any
assurances that Geoilbent's other shareholder will be willing or able to do so.
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 minority 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. country risk diversification.
OUR FOREIGN OPERATIONS EXPOSE US TO FOREIGN CURRENCY RISK.
Our principalforeign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela and Russia which havehas historically been considered a highly inflationary economies.economy. Results of operations in those countriesthat country are re-measuredmeasured in United StatesU.S. 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 currenciescurrency to the United StatesU.S. 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 Capital Resources and Liquiditybelow. 22
NEW YORK STOCK EXCHANGE DELISTING. In October 2001, we receivedSuccessful acquisition of projects in Russia may also expose us to foreign currency risk in that country.
The loss of key personnel could adversely affect our ability to successfully execute our strategy.We are a letter fromsmall organization and depend on the New York Stock Exchange ("NYSE") notifying us that we had fallen below the
continued listing standardskills and experience of the NYSE. These standards include a total market
capitalization of at least $50 million over a 30-day trading periodfew individuals in key management and stockholders' equity of at least $50 million. Accordingoperating positions 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 was $16.0 million as of September
30, 2001. In accordance with the NYSE's rules, we submitted a plan to the NYSE
detailing how we expected to reestablish compliance with the listing criteria
within the next 18 months. In January 2002, the NYSE acceptedexecute our business plan,
subject to quarterly reviewsstrategy. Loss of one or more key individuals in the goals and objectives 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.organization could hamper or delay achieving our strategy.
Leverage materially affects our operations. As of December 31, 2002,2003, our long-term debt was $104.7$96.8 million. Our long-term debt represented 3833 percent of our debt to total capitalcapitalization at December 31, 2002.2003. Our current
17
cash balances are in excess of these obligations and lessen the impact of our debt but itour long-term debt can effect our operations in several important ways, including the following:
o a significant portion of our cash flow from operations is used to
pay interest on borrowings;
o
| • | a significant portion of our cash flow from operations is used to pay interest on borrowings; | ||
| • | our single largest indebtedness of $85 million is due in November 2007; | ||
| • | the covenants contained in the indentures governing such debt limits 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 level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and | ||
| • | the terms of the indentures governing our debt permit our creditors to accelerate payments upon an event of default or a change of control. |
The total capital required for development of new fields may exceed our ability to finance.Our future capital requirements for new projects may exceed the cash available from existing free cash flow and cash on hand. Our ability to acquire financing is uncertain and may be affected by numerous factors beyond our control. Because of the financial risk factors in the countries in which we operate, we may not be able to secure either the equity or debt financing necessary to meet any future cash needs for investment, which may limit our ability to borrow additional fundsfully develop new projects, cause delays with their development or require early divestment of all or a portion of those projects.
Our current and future revenue is subject to disposeconcentrated counter-party risk.Our current operations in Venezuela rely on production fee payments from PDVSA for all revenue receipts. We do not own the hydrocarbons and do not sell oil and gas in open markets. Future projects in Venezuela, Russia and other countries may involve similar production fee payments from a limited number of assets;
ocompanies or governments.
We may not be able to invest the covenants containednet cash proceeds from the sale of Geoilbent in the indentures governing our debt affect
our flexibility in planning for,new oil and reacting to, changes in
business 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 other purposes; and
o thegas projects. The terms of the indentures governing2007 Notes require that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the sale, or any amount not so invested must be used to repay or prepay the 2007 Notes or certain debts of subsidiaries.
Oil price declines and volatility could adversely affect 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.revenue, cash flows and profitability. Prices for oil fluctuate widely. The average price we received for oil in Venezuela increased to $14.07 per Bbl for the year ended December 31, 2003, compared to $13.08 per Bbl for the year ended December 31, 2002, compared2002. In November 2003, we began selling natural gas in Venezuela under an addendum to $12.52our operating service contract at $1.03 per Bbl for the year ended December 31,
2001. OurMcf and Incremental Crude Oil at $7.00 per Bbl. While this diversifies our revenue stream, 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 writedownswrite-downs when prices decline. Lower prices may also reduce the amount of oil that we can produce economically.economically and lower oil production could affect the amount of natural gas we can produce. 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; | ||
| • | market uncertainty; | ||
| • | the level of consumer product demand; | ||
| • | weather conditions; | ||
| • | domestic and foreign governmental regulations; | ||
| • | the price and availability of alternative fuels; | ||
| • | political and economic conditions in oil-producing countries; and | ||
| • | overall economic conditions. |
Lower oil 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.natural gas prices or downward adjustments to our reserves may cause us to record ceiling limitation write-downs. 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"“ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10 percent,
18
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“ceiling limitation write-down"write-down”. This charge does not impact cash flow from operating activities, but does reduce stockholders'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. NoThe consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downs were
required in 2002.
23
ESTIMATES OF OIL AND NATURAL GAS RESERVES ARE UNCERTAIN AND INHERENTLY
IMPRECISE.2003. Equity in Net Losses of Affiliated Companies includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ending September 30, 2003.
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 CommissionSEC 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, 2002,2003, approximately 4647 percent of our estimated proved
reservesProved 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. SeeSupplemental Information on Oil and Natural Gas Producing Activities.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 CommissionSEC 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 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 CommissionSEC 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.
WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES.
We may not be able to replace production with new reserves. In general, the
volume of production rates and remaining reserves from oil and gas properties declinesdecline as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves in the South Monagas Unit in Venezuela will decline as they are produced unless we acquire additional properties in Venezuela, Russia or elsewhere with proved reserves or conduct successful exploration and development activities. Our future oil and natural gas 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.
19
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:
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
| • | unexpected drilling conditions; | ||
| • | pressure or irregularities in formations; | ||
| • | equipment failures or accidents; | ||
| • | weather conditions; | ||
| • | shortages in experienced labor; | ||
| • | shortages or delays in the delivery of equipment; and | ||
| • | delays in receipt of permits or access to lands. |
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.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 orand 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.
COMPETITION WITHIN THE INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS.
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 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 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 cannot 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 reduce the
amount of debt on the balance sheet;
2003 Financial and (ii) to improve the value of our
producing assets. We alsoOperational Performance
In 2003, we strengthened our management team and recommitted, as a management team and board of directors, added to maintainour financial flexibility by completing the highest standardssale of Geoilbent for $69.5 million in corporate governance, financial transparencycash plus $5.5 million for repayment of our intercompany debt and business ethics. In May 2002,accounts receivable, added a gas revenue stream and advanced our growth plan by announcing an agreement with PDVSA to study two oil and gas fields close to our facilities in Venezuela.
At December 31, 2003, we had $138.7 million of cash and a debt to total capitalization ratio of 33 percent compared with 38 percent at the shareholders approved our name change to Harvest Natural Resources, Inc. In
September 2002, ourend of 2002.
20
Our board of directors has authorized the repurchase of up to one million shares of our common stock. As ofIn March 11, 2003 we have 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 to be available
25
for acquisitions, reduction of debt or other general corporate purposes. This
strategy has already been partially rewarded by our ability to maintain our
financial flexibility in spite 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 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
administrative) 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 to PDVSA over
the next 10 years. Establishing a market for this gas allowed us to record 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
liabilities and accelerate the development of the South 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
2004 Capital Program
Benton-Vinccler’s capital expenditures for 20032004 are projected to be $45
to $50$30-35 million, compared with 20022003 capital expenditures of $43$58.1 million. To
partially fund itsThe 2004 capital program Benton-Vinccler borrowed $15.5 millionincludes plans for ten wells in October 2002 for the construction of the pipelineProved Undeveloped Reserves and related facilities to
deliverat Uracoa for approximately $18 million as well as the start of the engineering and design studies at East Bombal in anticipation of 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.sales in 2005.
In January 2003, we completed our Tucupitathree well Bombal Field development program in Venezuela. In 2003, Benton-Vinccler plans to drill three oil wells in the
Bombal FieldVenezuela and constructconstructed a pipeline from Bombal to the Tucupita delivery line. The Bombal drilling program delivered disappointing results. Instead of initial flush production with little or no water, the wells experienced early water breakthrough and consequently lower oil production. Benton-Vinccler also plans to convertconverted two gas injection wells in Uracoa to gas production. Other capital projects relate toproduction and completed the gas project and facilities improvements.
Geoilbent's capital expenditures for 2003 are projected to be
approximately $20improvements on time at a cost of $27 million. In 2003, Geoilbent plans to drill up to eighteen
wells in South Tarasovskoye and to commence a comprehensive work over program in
North Gubkinskoye. An appraisal well is planned in 2003 to delineate a potential
south extension
Results of the South Tarasovskoye field that will be developed with
further drilling if successful. Geoilbent expects to fund the South Tarasovskoye
drilling program through draw downs from the EBRD loan facility. For a
description of the EBRD loan agreement and a discussion of Geoilbent's
compliance with the covenants and possible liquidity problems, see Geoilbent's
Liquidity above and Note 9 - Russian Operations.
RESULTS OF OPERATIONSOperations
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 accountaccounted 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 yearyears ended December 31, 2003, 2002 and 2001 reflect the results of Geoilbent (until sold on September 25, 2003) and Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2003, 2002 2001 and 2000.2001.
You should read the following discussion of the results of operations for each of the years in the three-year period ended December 31, 20022003 and the financial condition as of December 31, 20022003 and 20012002 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 salesrevenue in the following table:
YEARS ENDED DECEMBER 31,
-------------------------
2002 2001 2000
---- ---- ----
Operating Expenses 27% 35% 34%
Depletion, Depreciation and Amortization 21 21 12
General and Administrative 13 16 12
Taxes Other Than on Income 3 4 3
Interest 13 20 21
YEARS ENDED DECEMBER
| Years Ended December 31, | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Operating Expenses | 29 | % | 27 | % | 35 | % | ||||||
| Depletion, Depreciation and Amortization | 20 | 21 | 21 | |||||||||
| General and Administrative | 15 | 13 | 16 | |||||||||
| Taxes Other Than on Income | 3 | 3 | 4 | |||||||||
| Interest | 10 | 13 | 20 | |||||||||
Years ended December 31, 2003 and 2002 AND 2001
Net income for the year ended 2003 was $27.3 million, or $0.74 per diluted share, compared with $100.4 million for the year ended 2002. The $27.3 million net income included the gain from the sale of our minority equity investment in Geoilbent of $46.6 million, $0.4 million partial recovery of a bad debt and $1.5 million arbitration settlement related to A. E. Benton (SeeNote 13 – Related Party Transactions). Operating and general and administrative expenses were reduced by $3.8 million, or almost 8 percent, compared with 2002.
Our results of operations for the year 2003 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted for all of our production and oil and gas sales revenue. Oil revenue per barrel increased 8 percent (from $13.05 in 2002 to $14.07 in 2003) and oil sales quantities decreased 24 percent (from 9.7 MBbl of oil in 2002 to 7.3 MBbl of oil in 2003) during the year ended 2003 compared with 2002. Gas sales began on November 25, 2003, at the contract rate of $1.03 per Mcf. Incremental Crude Oil sales began on the same date at a fixed price of $7.00 per barrel. Total gas sales were 2.7 Bcf for the period.
Our revenues decreased $20.6 million, or 16 percent, during the year ended 2003 compared with 2002. This was primarily due to lower production offset by higher world crude oil prices. Our sales quantities for the year ended
21
2003 from Venezuela were 7.8 MBoe compared with 9.7 MBoe in 2002. The decrease in sales quantities of 1.9 MBoe, or 20 percent, was due to the Venezuelan national civil work stoppage which led to the shut-in of our production from December 2002 to February 2003, natural reservoir decline rates and the fact that some wells did not immediately return to previous production levels following the national work stoppage.
Our operating expenses decreased $3.1 million, or 9 percent, for the year ended 2003 compared with 2002. This was primarily due to lower production volumes partially offset by higher workover and maintenance programs that continued during the Venezuelan national civil work stoppage. Depletion, depreciation and amortization decreased $5.2 million, or 20 percent, during the year 2003 compared with 2002 primarily due to decreased production from Venezuela and the addition of natural gas reserves in 2002. Depletion expense per barrel of oil produced from Venezuela during 2003 was $2.52 compared with $2.56 during 2002 primarily due to reduced future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during the year ended 2003 compared with $13.4 million for the impairment of the China WAB-21 block and $1.1 million for the Lakeside Prospect exploration activities during the year ended 2002. General and administrative expenses decreased $0.8 million from 2002 to 2003. An arbitration settlement of $1.5 million and a bad debt recovery of $0.4 million were recorded in the third quarter of 2003, and a bad debt recovery of $3.3 million was recorded in the third quarter of 2002 related to A. E. Benton.
Taxes other than on income decreased $0.7 million, or 17 percent, during the year ended 2003 compared with 2002. This was primarily due to decreased Venezuelan municipal taxes which are a function of oil revenues partially offset by a one-time adjustment of U.S. employment taxes of $0.7 million in 2002.
Investment income and other decreased $0.7 million, or 32 percent, during the year ended 2003 compared with 2002. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $5.9 million, or 36 percent, during the year ended 2003 compared with 2002 due to lower average outstanding debt balances for the year ended 2003 compared to 2002. In 2002, we redeemed all $108 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 $15.5 million to finance the construction of the gas pipeline in Venezuela from the Uracoa field to the PDVSA sales line, and we repaid all Bolivar denominated debt in March 2003.
Net gain on exchange rates decreased $4.0 million, or 88 percent, for the year ended 2003 compared with 2002. This was due to the significant devaluation of the Bolivar and Bolivar currency controls imposed in February 2003 which fixed the exchange rate between the Bolivar and the U.S. dollar and restricts the ability to exchange Venezuelan Bolivars for dollars and vice versa. We realized income before income taxes and minority interest of $71.8 million during the year 2003 compared with income of $169.8 million in the year ended 2002. The decrease was primarily attributable to the Arctic Gas Sale in 2002 offset by the sale of our minority equity investment in Geoilbent in 2003. Income tax expense decreased $50.6 million due to lower pre-tax income. The effective tax rate decreased from 36 to 13 percent for the year ended 2003 compared with 2002. The rate decrease was due to an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the benefit was fully reserved in historical periods. The income before minority interests decreased $47.4 million for the year ended 2003 compared with 2002. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by decreased production of Benton-Vinccler.
Equity in net losses of affiliated companies decreased $29.0 million during the year 2003 from $0.2 million in 2002 to a loss of $28.9 million in 2003. This was primarily due to full cost ceiling test writedowns of $32.3 million (our share) and decreased income from Geoilbent. SeeNote 9 – Russian Operations. The year ended 2002 included a loss of $1.5 million on Arctic Gas.
Years ended December 31, 2002 and 2001
Net income for the year ended 2002 was $100.4 million, or $2.78 per diluted share, compared with $43.2 million for the same period last
year.2001. The $100.4 million net income included the after-tax gain from the Arctic Gas Sale of $93.6 million, and the pre-tax $3.3 million, partial recovery of a bad debt related to A. E. Benton (SeeNote 13 -– Related Party Transactions)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.
22
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 Venezuelan 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$2.56 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$108 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 income taxes and minority interest of $169.8 million during the year ended December 31, 2002 compared with $7.2 million in 2001. 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 net operating loss carry forwards in 2002. Income tax expense decreased $105.0 million due to the reversal of a substantial portion of the valuation allowance on U.S. net operation loss carryforwards in 2001. The effective tax rate in 2002 of 36 percent reflects foreign income taxes incurred on profitable foreign operations and an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the approximate rate for Venezuela and no tax
benefits are being recognized for expenses incurredbenefit was fully reserved in the U.S.historical periods. The income attributable to thebefore minority interestinterests 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 reduced expenses of Benton-Vinccler.
Equity in net 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 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
23
Capital Resources 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 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, 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. 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 LIQUIDITYLiquidity
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
| • | drilling and completion costs of wells and the cost of production, treating and transportation facilities; | ||
| • | geological, geophysical and seismic costs; and | ||
| • | acquisition of interests in oil and gas properties. |
The amount of available capital will affect the scope of our operations and the rate of our growth. OurWe began selling Venezuelan natural gas in November 2003, but 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. 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 AdministrationGovernment of Foreign Currency
("CADIVI") with the task of establishing the detailed rules and regulations and
generally administering the exchange control regime. The currency controls fixVenezuela fixed the exchange rate between the Bolivar and the U.S. dollar, and restrictsrestricted the ability to exchange Venezuelan Bolivars for U.S. dollars and vice versa. Initially the exchange rate was fixed at 1,600 Venezuelan Bolivars for each U.S. dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar. Oil companies, such as Benton-Vinccler are allowed to receive payments for oil sales in U.S. currencydollars and pay U.S. 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 beof the Bolivar denominated debt was repaid onas of March 31, 2003. As of February 24, 2003,March 1, 2004, we have cash reserves of approximately $75$156.0 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, 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 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.We currently have a significant debt principal obligation payable in 2007 ($85 million). We intendBy September 24, 2004, we may be obligated to continue to evaluate open marketrepay or prepay some portion of this debt purchaseswith some of the obligations due in 2007 to further reduce debt.net cash proceeds from the sale of Geoilbent (seeRisk Factors). In 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan commercial bank for the construction of a Tucupita to Uracoaan oil pipeline. Benton-Vinccler has providedA portion of the thirty day noticeloan was denominated in Bolivars and was repaid as 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 $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 regardingoperating service agreement for 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. At December 31, 2002, we had $91.9 million of cash or cash
equivalents.
Benton-Vinccler's
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 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reducesreduced 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.waiver under acceptable terms and conditions.
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:
24
| Year Ended December 31, | ||||||||||||
| (in thousands) | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| Net cash provided by operating activities | $ | 38,538 | $ | 42,627 | $ | 36,608 | ||||||
| Net cash provided by (used in) investing activities | 38,191 | 126,143 | (48,082 | ) | ||||||||
| Net cash provided by (used in) financing activities | (2,570 | ) | (113,293 | ) | 5,366 | |||||||
| Net increase (decrease) in cash | $ | 74,159 | $ | 55,477 | $ | (6,108 | ) | |||||
At December 31, 2002,2003, we had current assets of $132.0$183.4 million and current liabilities of $35.0$46.2 million, resulting in working capital of $137.2 million and a current ratio of 4.0:1. This compares with a working capital of $97.0 million and a current ratioration of 3.8:1. This compares with a negative working
capital of $0.6 million and a negative current ratio1 at December 31, 2001.2002. The increase in working capital of $97.6$40.2 million was primarily due to higher oil
prices and the Arctic Gas Sale.
sale of our minority equity investment in Geoilbent.
Cash Flow from Operating Activities.During the years ended December 31, 20022003 and 2001,2002, net cash provided by operating activities was approximately $42.6$38.5 million and $36.6$42.6 million, respectively. The $6.0$4.1 million increasedecrease was primarily due to higherlower oil revenues and lower operating expenses.
offset by the commencement of gas sales in the fourth quarter of 2003.
Cash Flow from Investing Activities.During the yearyears ended December 31, 20022003 and 2001,2002, we had drilling and production-related capital expenditures of approximately $43.3$60.9 million and $43.4$43.3 million, respectively. Of the 20022003 expenditures, $42.5$33.6 million was attributable to the development of the South Monagas Unit, $27.0 million to the construction of the gas pipeline and $0.8 million was attributable to Lakeside Exploration Prospect.the balance for other administrative property.
The timing and size of capital expenditures for the South Monagas Unit are entirely at our discretion. We anticipate that Geoilbent will continue to
fund its expenditures through its own cash flow and credit facilities. Our remaining capital commitments worldwide support our search for new acquisitions, and are relatively minimal and are substantially at our discretion. We will also be required to make annual interest payments of approximately $8.0 million on the 2007 Notes.
We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements.
Benton-Vinccler entered into a commodity contract (costless collar) in 2002 and,
as described above, a WTI crude oil "put" for a portion of 2003.
Cash Flow from Financing Activities.During 2003, Benton-Vinccler repaid the balance of their Bolivar denominated debt of $2.2 million and other debt of $1.2 million. During 2002, we paid $108 million in 11.625 percent senior unsecured notes due May 1, 2003, $20 million in 9.375 percent senior unsecured notes due November 1, 2007 and Benton-Vinccler repaid other debt of $4.3 million. In November 1997, we issued $115 million in 9.375 percent senior unsecured notes due November 1, 2007, of which we subsequently repurchased $30 million at their par value for cash.million. Interest on these notes is due May 1st1 and November 1st1 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, 2002,2003, we were in compliance with all covenants of the indenture.
Contractual Obligations.We have ana lease obligation of 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.
2003.
PAYMENTS (IN THOUSANDS) DUE BY PERIOD
-------------------------------------------------------------------------
LESS THAN AFTER 4
CONTRACTUAL OBLIGATION TOTAL 1 YEAR 1-2 YEARS 3-4 YEARS YEARS
---------------------- ----------- ----------- ----------- ----------- -----------
Long Term Debt $ 106,567 $ 1,867 $ 7,035 $ 7,035 $ 90,630
Building Lease 264 132 132 -- --
----------- ----------- ----------- ----------- -----------
Total $ 106,831 $ 1,999 $ 7,167 $ 7,035 $ 90,630
=========== =========== =========== =========== ===========
| Payments (in thousands) Due by Period | ||||||||||||||||
| Less than | ||||||||||||||||
| Contractual Obligation | Total | 1 Year | 1-3 Years | 3-5 Years | ||||||||||||
| Long Term Debt | $ | 103,200 | $ | 6,367 | $ | 6,367 | $ | 90,466 | ||||||||
| Office Lease | 88 | 88 | — | — | ||||||||||||
| Total | $ | 103,288 | $ | 6,455 | $ | 6,367 | $ | 90,466 | ||||||||
While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash and 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 prices, 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 that PDVSA will timely pay our invoices. Actual results could be materially affected if there is a significant change in our expectations or assumptions. Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well
25
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.
We currently have a significant debt obligation of $85 million payable in November 2007. Our ability to meet our debt obligation and to reduce our level of debt depends on the successful implementation of our strategic
objectives.
31
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATIONbusiness strategy.
Effects of Changing Prices, Foreign Exchange Rates and Inflation
Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil and natural gas prices may affect our total planned development activities and capital expenditure program.
There are presently no restrictions in Russia that restrict converting
U.S. dollars into local currency or local currency into U.S. dollars for routine
business operations, such as the payments of invoices, and debt obligations
within the Russian Federation.
As noted above under CAPITAL RESOURCES AND
LIQUIDITY,Capital Resources and Liquidity, Venezuela imposed currency exchange restrictions onin February 5, 2003.2003, and adjusted the official exchange rate in February 2004. We are unable to predict the impact ofdo not expect the currency controlsconversion restrictions or the adjustment in the exchange rate to have a material impact on us or
Benton-Vinccler as the Government has not issued final regulations.at this time.
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.Venezuela. 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 a minor amount of local transactions in Russia and Venezuela are conducted in local currency. If the rate of increase in the value of the U.S. 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, 2002, our net foreign exchange gain attributable to our international operations was $4.6 million. The U.S. dollar and Bolivar exchange rates were fixed in February 2003 and no gains or losses were recognized after February 2003. 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 currenciescurrency 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.
CRITICAL ACCOUNTING POLICIES
Critical Accounting Policies
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 and Arctic Gas based on a fiscal year ending September 30.30 prior to their respective sales.
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.
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. 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 offor China unproved properties are excluded from amortization until the properties are evaluated. We regularlyAt least annually, we evaluate our unproved properties on a
country-by-country basisproperty for possible impairment. If we abandon all exploration efforts in a countryChina where no proved reserves are assigned, all exploration and acquisition costs associated with the country arewill be expensed. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.
The 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
26
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. 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
Proved Reservesproved 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
reserveProved 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 reserveProved 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.SEC. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter and require a write-downwrite–down if our capitalized costs exceed this "ceiling,"“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 1998.1998 other than the write-downs recorded by our equity affiliates. 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 near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from 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.
FOREIGN CURRENCY
We have significant
Foreign Currency
Our current operations outside of the United States,
principallyare in VenezuelaVenezuela. The U.S. dollar is our functional and an equity investment in Russia.reporting currency. Amounts denominated in non-U.S. currencies are re-measured in United StatesU.S dollars, and all currency gains or losses are recorded in the statement of income.operations. We attempt to manage our operations in such a manner as 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 currenciesBolivar to the United StatesU.S. dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.
New Accounting Pronouncements
In September 2001,May 2003, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting StandardsStandard No. 143, Accounting150 “Accounting for Asset
Retirement Obligations (SFAS No. 143)Certain Financial Instruments with Characteristics of both Liabilities and Equity” (the “Statement”). SFAS No. 143 requires entities to recordThe Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement is generally effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at 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 amountbeginning 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 yearsfirst interim period beginning after SeptemberJune 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. Further we believe the2003. The adoption of SFAS No.
143 by Geoilbent will not materially impactthis Statement had no effect on our equity in earnings given that
the fair value of such obligations are not material as of September 30, 2002.consolidated financial statements.
In May 2002,January 2003, the FASB issued SFASInterpretation No. 145, Rescission46 (“FIN 46”) Consolidation of FASB
Statements No. 4, 44, and 64, AmendmentVariable Interest Entities, which addresses the consolidation 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
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 date of a commitment to an exit or disposal plan.
Examples of costs coveredvariable interest entities (“VIEs”) by the standard include lease termination costs and
certain employee severance costsbusiness enterprises 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 Statement No. 123 that provides
alternative methods of transition forprimary beneficiaries. A VIE is 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 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,sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or FIN 46, "Consolidation of
Variable Interest Entities" was issued. FIN 46 identifies certain off-balance
sheet arrangements that meetwhose equity investors lack the definitioncharacteristics of a variable interest entity (VIE).controlling financial interest. The primary beneficiary of a VIE is the partyenterprise that is exposed tohas the
27
majority of the risks and/or returns ofrewards associated with the VIE. In future accounting periods,December 2003, the primary
beneficiary will be requiredFASB issued a revision to consolidate the VIE. In addition, more extensive
disclosure requirements applyFIN 46, Interpretation No. 46R (“FIN 46R”), to the primary beneficiary, as well as other
significant investors. We do not believe we participate in any arrangement that
would be subject toclarify some of the provisions of FIN 46.
In November 2002,46, and to defer certain entities from adopting until the International Practices Task Force concluded that
Russia has ceased being a highly inflationary economy as of January 1, 2003. As
a resultend of the Task Force conclusion, companiesfirst interim or annual reporting under US GAAPperiod ending after March 15, 2004. Application of FIN 46R is required in Russia will befinancial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types of VIEs is required to applyin financial statements for periods ending after March 15, 2004. We believe we have no arrangements that would require the guidance contained in Emerging Issues Task
Force ("EITF") No. 92-4 and EITF No. 92-8 asapplication of January 1, 2003.FIN 46R. We have not yet
estimated the effect that EITF No. 92-4no material off-balance sheet arrangements.
Item 7A. Quantitative and EITF No. 92-8 will have on Geoilbent
or our equity position.
35
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKQualitative Disclosures About Market Risk
We are exposed to market risk from adverse changes in oil and natural gas prices, interest rates, foreign exchange and political risk, as discussed below.
OIL PRICES
Oil Prices
As an independent oil 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 natural gas. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Historically, prices received for oil production have been volatile and unpredictable, and such volatility is expected to continue. Through February 14, 2003, we utilized a costless collar hedge transaction with respect to a portion of our oil production to achieve a more predictable cash flow, and establish an acceptable rate of return on our Tucupita drilling program, as well as to reduce our exposure to price fluctuations. Benton-Vinccler has hedged a portion of its 2003 oil production by purchasing a WTI crude oil "put"“put” to protect its 2003 cash flow. 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. SeeNote 1 -– Derivatives and Hedgingfor a complete discussion of our derivative activity. INTEREST RATESCurrently, we have no hedging transactions in place for our 2004 production.
Interest Rates
Total long-term debt at December 31, 20022003 of $104.7$96.8 million consisted of fixed-rate senior unsecured notes maturing in 2007 ($85.0 million). Benton-Vinccler has $18.2$11.8 million of U.S. Dollar denominated and 1.5 million
Bolivardollar denominated variable rate loans. A hypothetical 10 percent adverse change in the interest rate would not have had a material affect on our results of operations.
FOREIGN EXCHANGE
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 financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in these countries. Venezuela has recently imposed currency exchange controls (see
CAPITAL RESOURCES AND LIQUIDITY Capital Resources and Liquidityabove).
POLITICAL RISK
The stability of government
Political Risk
Political and economic uncertainty remains very high in Venezuela. During 2003, 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 government's
relationship with the state-owned national oil company, PDVSA, remain
significant risksSouth Monagas Unit decreases significantly 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 oil
production was not interrupted, but it did delay the importation of critical
equipment, which contributed to the slowdown in our drilling operations.any reason. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA'sPDVSA’s inability to accept our oil due to the national civil work stoppage.stoppage in Venezuela. As a result, 2002 sales were reduced by approximately 550,0000.6 million barrels and 2003 sales in
2003 were reduced by an estimated 1.2 million barrels. While the situation has
stabilized and production is returning to normal, there continues to be
political and economic uncertainty that could lead to another disruption of our
sales. As a result of the Venezuelan national civil work stoppage, the Government of
VenezuelaVenezuelan government terminated several thousand PDVSA employees and announced a decentralizationrestructuring of PDVSA'sPDVSA’s operations. While the effect of theseThroughout 2003, there have been numerous organizational 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.in PDVSA. As a result of the situation in PDVSA, its payment to Benton-Vinccler for crude delivered in the fourth quarter of 2002 was late by seven days. WeHowever, all other payments have been on time, and we believe that the payment demonstrates PDVSA's commitmentPDVSA is committed to building its production levels back to full capacity and returning to more normalized business relations with its customers and suppliers.
28
There are ongoing efforts by opponents of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of the changes and the possible politicalization of PDVSA 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. Organizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing of those acquisitions. While we have substantial cash reserves to withstand a future disruption of sales, 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.
36
ITEM
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAFinancial Statements and Supplementary Data
The information required by this item is included herein on pages S-1 through S-37.
ITEMS-36.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSUREChanges in and Disagreements with Accountants on 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*
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)
------------------ --------------- ---------------- --------------------
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
=========== ========== ===========
(1) See Note 6 of Notes to Consolidated Financial Statements for a
description of options issued to individuals other than officers,
directors or employees of the Company.
Item 9A. Controls and Procedures
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, 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'sregistrant’s quarterly and annual reports under the Securities Exchange Act of 1934 (the "Exchange Act"“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, 2002,2003, of our disclosure controls and procedures (as defined in Rule 13a-14(c)13a-15(e) and Rule 15d-14(c)15d-15(e) 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 have we been required to take any corrective actions with regard to any significant deficiencies and material weaknesses.
39
29
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. IndexIII
Item 10. Directors and Executive Officers of the Registrant
Please refer to Financial Statements: Page
----
Reportthe information under the captions “Election of Independent Accountants .................................S-1
Consolidated Balance Sheets at December 31, 2002Directors” and 2001..........S-2
Consolidated Statements of Operations“Executive Officers” in our Proxy Statement for the Years Ended
December 31, 2002, 2001 and 2000...................................S-3
Consolidated Statements2004 Annual Meeting of Stockholders' EquityShareholders.
Item 11. Executive Compensation
Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the Years Ended December 31, 2002, 2001,2004 Annual Meeting of Shareholders.
Item 12. Security Ownership of Certain Beneficial Owners and 2000......................S-4
Consolidated Statements of Cash FlowsManagement
Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the Years Ended
December 31, 2002, 2001,2004 Annual Meeting of Shareholders.
Item 13. Certain Relationships and 2000..................................S-5
NotesRelated Transactions
Please refer to Consolidatedthe information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 2004 Annual Meeting of Shareholders.
Item 14. Principal Accounting Fees and Services
Please refer to the “Independent Accountants” in our Proxy Statement for the 2004 Annual Meeting of Shareholders.
30
PART IV
Item 15. Exhibits, Financial Statements.........................S-7
Statement Schedules and Reports on Form 8-K
| Page | ||||
| (a) 1. | Index to Financial Statements: | |||
| Report of Independent Auditors | S-1 | |||
| Consolidated Balance Sheets at December 31, 2003 and 2002 | S-2 | |||
| Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001 | S-3 | |||
| Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001 | S-4 | |||
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 | 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
| 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
| 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 | Amended and Restated Bylaws as of December 11, 2003. | |||||
| 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. (Incorporated by reference to 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. (Incorporated by reference to 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 | 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)). |
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.
| 10.3 | 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). | |||||
| 10.4 | 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). | |||||
| 10.5 | 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.). | |||||
| 10.6 | 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.). | |||||
| 10.7 | 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.). | |||||
| 10.8 | 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.) | |||||
| 10.9 | 2001 Long Term Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900)). | |||||
| 10.10 | 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.) | |||||
| 10.11 | 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.) | |||||
| 10.12 | 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.) | |||||
| 10.13 | 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.) | |||||
| 10.14 | 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.) | |||||
| 10.15 | 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.) | |||||
| 10.16 | 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.) | |||||
| 10.17 | Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.) | |||||
| 10.18 | Employment Agreement dated November 17, 2003 between Harvest Natural Resources, Inc. |
32
| and Karl L. Nesselrode. | ||||||
| 21.1 | List of subsidiaries. | |||||
| 23.1 | Consent of PricewaterhouseCoopers LLP - Houston | |||||
| 23.2 | Consent of ZAO PricewaterhouseCoopers Audit - Moscow | |||||
| 23.3 | Consent of Ryder Scott Company, LP | |||||
| 31.1 | Certification of the Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||
| 31.2 | Certification of the Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||
| 32.1 | Certifications accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
(b) Reports on Form 8-K
On December 11, 2002,October 10, 2003, we filed ana Current Report on Form 8-K for a press release dated
December 10, 2002, announcingdisclosing the implementationUnaudited Pro Forma results from the sale of an operational contingency
plan for the Company's operationsour minority equity investment in Venezuela.Geoilbent.
On December 19, 2002,November 6, 2003, we filed ana Current Report on Form 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
33
REPORT OF INDEPENDENT ACCOUNTANTS
AUDITORS
To the Board of Directors
and Stockholders of Harvest Natural Resources, Inc.
In our opinion, the accompanying consolidated balance sheets andfinancial statements listed in the related
consolidated statements of operations, of stockholders' equity and of cash flowsindex appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31, 20022003 and 2001,2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20022003 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'sCompany’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, the Company changed its method of accounting for employee stock-based compensation 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.
fair value based method effective January 1, 2003.
PricewaterhouseCoopers LLP
Houston, Texas
March 28, 2003
4, 2004
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
=========== ===========
| December 31, | ||||||||||||
| 2003 | 2002 | |||||||||||
| (in thousands, except per | ||||||||||||
| share data) | ||||||||||||
| ASSETS | ||||||||||||
| Current Assets: | ||||||||||||
| Cash and cash equivalents | $ | 138,660 | $ | 64,501 | ||||||||
| Restricted cash | 12 | 1,812 | ||||||||||
| Marketable securities | — | 27,388 | ||||||||||
| Accounts and notes receivable: | ||||||||||||
| Accrued oil sales | 32,766 | 27,359 | ||||||||||
| Joint interest and other, net | 11,197 | 8,002 | ||||||||||
| Prepaid expenses and other | 805 | 2,969 | ||||||||||
| Total Current Assets | 183,440 | 132,031 | ||||||||||
| Restricted Cash | 16 | 16 | ||||||||||
| Other Assets | 2,080 | 2,520 | ||||||||||
| Deferred Income Taxes | 4,749 | 4,082 | ||||||||||
| Investments In and Advances To Affiliated Companies | — | 51,783 | ||||||||||
| Property and Equipment: | ||||||||||||
| Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2003 and 2002, respectively) | 593,622 | 576,601 | ||||||||||
| Other administrative property | 8,948 | 7,503 | ||||||||||
| 602,570 | 584,104 | |||||||||||
| Accumulated depletion, depreciation, and amortization | (418,507 | ) | (439,344 | ) | ||||||||
| Net Property and Equipment | 184,063 | 144,760 | ||||||||||
| $ | 374,348 | $ | 335,192 | |||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||
| Current Liabilities: | ||||||||||||
| Accounts payable, trade and other | $ | 4,163 | $ | 3,804 | ||||||||
| Accounts payable, related party | 10,375 | 9,779 | ||||||||||
| Accrued expenses | 15,251 | 10,865 | ||||||||||
| Accrued interest payable | 1,427 | 1,405 | ||||||||||
| Income taxes payable | 8,647 | 6,880 | ||||||||||
| Commodity hedging contract | — | 430 | ||||||||||
| Current portion of long-term debt | 6,367 | 1,867 | ||||||||||
| Total Current Liabilities | 46,230 | 35,030 | ||||||||||
| Long-Term Debt | 96,833 | 104,700 | ||||||||||
| Asset Retirement Liability | 1,459 | — | ||||||||||
| Commitments and Contingencies | — | — | ||||||||||
| Minority Interest | 30,113 | 24,145 | ||||||||||
| 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, 2003 and 2002; issued 36,405 shares and 35,900 shares at December 31, 2003 and 2002, respectively | 364 | 359 | ||||||||||
| Additional paid-in capital | 175,051 | 173,559 | ||||||||||
| Retained earnings | 27,537 | 234 | ||||||||||
| Treasury stock, at cost, 730 shares and 650 shares at December 31, 2003 and 2002, respectively | (3,239 | ) | (2,835 | ) | ||||||||
| Total Stockholders’ Equity | 199,713 | 171,317 | ||||||||||
| $ | 374,348 | $ | 335,192 | |||||||||
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
=========== =========== ===========
| Years Ended December 31, | |||||||||||||
| 2003 | 2002 | 2001 | |||||||||||
| (in thousands, except per share data) | |||||||||||||
Revenues | |||||||||||||
| Oil sales | $ | 103,920 | $ | 127,015 | $ | 122,386 | |||||||
| Gas sales | 2,740 | — | — | ||||||||||
| Ineffective hedge activity | (565 | ) | (284 | ) | — | ||||||||
| 106,095 | 126,731 | 122,386 | |||||||||||
Expenses | |||||||||||||
| Operating expenses | 30,893 | 33,950 | 42,759 | ||||||||||
| Depletion, depreciation and amortization | 21,188 | 26,363 | 25,516 | ||||||||||
| Write-downs of oil and gas properties and impairments | 165 | 14,537 | 468 | ||||||||||
| General and administrative | 15,746 | 16,504 | 20,072 | ||||||||||
| Arbitration settlement | 1,477 | — | — | ||||||||||
| Bad debt recovery | (374 | ) | (3,276 | ) | — | ||||||||
| Taxes other than on income | 3,373 | 4,068 | 5,370 | ||||||||||
| 72,468 | 92,146 | 94,185 | |||||||||||
| Income from Operations | 33,627 | 34,585 | 28,201 | ||||||||||
| Other Non-Operating Income (Expense) | |||||||||||||
| Gain on disposition of assets | 46,619 | 144,029 | — | ||||||||||
| Gain on early extinguishment of debt | — | 874 | — | ||||||||||
| Investment earnings and other | 1,418 | 2,080 | 3,088 | ||||||||||
| Interest expense | (10,405 | ) | (16,310 | ) | (24,875 | ) | |||||||
| Net gain on exchange rates | 529 | 4,553 | 768 | ||||||||||
| 38,161 | 135,226 | (21,019 | ) | ||||||||||
| Income from Consolidated Companies Before Income | |||||||||||||
| Taxes and Minority Interest | 71,788 | 169,811 | 7,182 | ||||||||||
| Income Tax Expense (Benefit) | 9,657 | 60,295 | (35,698 | ) | |||||||||
| Income Before Minority Interest | 62,131 | 109,516 | 42,880 | ||||||||||
| Minority Interest in Consolidated Subsidiary Companies | 5,968 | 9,319 | 5,545 | ||||||||||
| Income from Consolidated Companies | 56,163 | 100,197 | 37,335 | ||||||||||
| Equity in Net Income (Losses) of Affiliated Companies | (28,860 | ) | 165 | 5,902 | |||||||||
| Net Income | $ | 27,303 | $ | 100,362 | $ | 43,237 | |||||||
| Net Income Per Common Share: | |||||||||||||
| Basic | $ | 0.77 | $ | 2.90 | $ | 1.27 | |||||||
| Diluted | $ | 0.74 | $ | 2.78 | $ | 1.27 | |||||||
See accompanying notes to consolidated financial statements.
S-3
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS'STOCKHOLDERS’ EQUITY
(in
(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
=========== =========== =========== ========== =========== ===========
| Retained | |||||||||||||||||||||||||
| Common | Additional | Earnings | |||||||||||||||||||||||
| Shares | Common | Paid-in | (Accumulated | Treasury | |||||||||||||||||||||
| Issued | Stock | Capital | Deficit) | Stock | Total | ||||||||||||||||||||
Balance at January 1, 2001 | 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 | ||||||||||||||||||
| Issuance of common shares: | |||||||||||||||||||||||||
| Exercise of stock options | 505 | 5 | 1,196 | — | — | 1,201 | |||||||||||||||||||
| Employee stock based compensation | — | — | 296 | — | — | 296 | |||||||||||||||||||
| Treasury stock (80 shares) | — | — | — | — | (404 | ) | (404 | ) | |||||||||||||||||
| Net Income | — | — | — | 27,303 | — | 27,303 | |||||||||||||||||||
Balance at December 31, 2003 | 36,405 | $ | 364 | $ | 175,051 | $ | 27,537 | $ | (3,239 | ) | $ | 199,713 | |||||||||||||
See accompanying notes to consolidated financial statements.
S-4
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in
(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
=========== =========== ===========
| Years Ended December 31, | |||||||||||||||
| 2003 | 2002 | 2001 | |||||||||||||
| (in thousands) | |||||||||||||||
| Cash Flows From Operating Activities: | |||||||||||||||
| Net income | $ | 27,303 | $ | 100,362 | $ | 43,237 | |||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||
| Depletion, depreciation and amortization | 21,188 | 26,363 | 25,516 | ||||||||||||
| Write-down and impairment of oil and gas properties | 165 | 14,537 | 468 | ||||||||||||
| Amortization of financing costs | 497 | 1,745 | 1,179 | ||||||||||||
| Gain on disposition of assets | (46,619 | ) | (144,029 | ) | (336 | ) | |||||||||
| Equity in net earnings (losses) of affiliated companies | 28,860 | (165 | ) | (5,902 | ) | ||||||||||
| Allowance for employee notes and accounts receivable | (169 | ) | (2,987 | ) | 365 | ||||||||||
| Non-cash compensation related charges | 296 | 1,458 | 474 | ||||||||||||
| Minority interest in undistributed earnings of subsidiaries | 5,968 | 9,319 | 5,545 | ||||||||||||
| Gain from early extinguishment of debt | — | (874 | ) | — | |||||||||||
| Tax benefits related to stock option compensation | — | — | 11,008 | ||||||||||||
| Deferred income taxes | (667 | ) | 53,618 | (53,407 | ) | ||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||
| Accounts and notes receivable | (7,935 | ) | (1,972 | ) | 11,756 | ||||||||||
| Prepaid expenses and other | 2,164 | (1,130 | ) | 565 | |||||||||||
| Accounts payable | 359 | (4,328 | ) | (4,671 | ) | ||||||||||
| Accounts payable, related party | 4,386 | (604 | ) | (1,662 | ) | ||||||||||
| Accrued interest payable | 22 | (2,489 | ) | 161 | |||||||||||
| Accrued expenses | (76 | ) | (9,686 | ) | 1,705 | ||||||||||
| Asset retirement liability | 1,459 | — | — | ||||||||||||
| Commodity hedging contract | (430 | ) | 430 | — | |||||||||||
| Income taxes payable | 1,767 | 3,059 | 607 | ||||||||||||
| Net Cash Provided by Operating Activities | 38,538 | 42,627 | 36,608 | ||||||||||||
| Cash Flows from Investing Activities: | |||||||||||||||
| Proceeds from sale of investment | 69,500 | 189,841 | — | ||||||||||||
| Additions of property and equipment | (60,925 | ) | (43,346 | ) | (43,364 | ) | |||||||||
| Investment in and advances to affiliated companies | 2,328 | 9,185 | (16,855 | ) | |||||||||||
| Increase in restricted cash | — | (2,800 | ) | (57 | ) | ||||||||||
| Decrease in restricted cash | 1,800 | 1,000 | 10,961 | ||||||||||||
| Purchases of marketable securities | (256,058 | ) | (353,478 | ) | (15,067 | ) | |||||||||
| Maturities of marketable securities | 283,446 | 326,090 | 16,370 | ||||||||||||
| Investment selling costs | (1,900 | ) | (349 | ) | (70 | ) | |||||||||
| Net Cash Provided by (Used In) Investing Activities | 38,191 | 126,143 | (48,082 | ) | |||||||||||
| Cash Flows from Financing Activities: | |||||||||||||||
| Net proceeds from exercise of stock options | 1,201 | 3,345 | — | ||||||||||||
| Purchase of treasury stock | (404 | ) | — | — | |||||||||||
| Proceeds from issuance of notes payable | — | 15,500 | 21,112 | ||||||||||||
| Payments on notes payable | (3,367 | ) | (132,138 | ) | (15,746 | ) | |||||||||
| Net Cash Provided by (Used In) Financing Activities | (2,570 | ) | (113,293 | ) | 5,366 | ||||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 74,159 | 55,477 | (6,108 | ) | |||||||||||
| Cash and Cash Equivalents at Beginning of Year | 64,501 | 9,024 | 15,132 | ||||||||||||
| Cash and Cash Equivalents at End of Year | $ | 138,660 | $ | 64,501 | $ | 9,024 | |||||||||
| Supplemental Disclosures of Cash Flow Information: | |||||||||||||||
| Cash paid during the year for interest expense | $ | 13,241 | $ | 19,201 | $ | 25,721 | |||||||||
| Cash paid during the year for income taxes | $ | 4,254 | $ | 3,935 | $ | 3,057 | |||||||||
See accompanying notes to consolidated financial statements.
S-5
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Supplemental Schedule of Noncash Investing and Financing Activities:
For the three years ended December 31, 2002,2003, 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, 2002,2003, 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 (seeNote 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
Note 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATIONOrganization 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 (Benton -Vinccler C.A. or “Benton-Vinccler”) and, until September 25, 2003, through our minority equity interestinvestment in our entity in Russia.
PRINCIPLES OF CONSOLIDATIONLLC Geoilbent, a Russian entity.
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 accountaccounted for our investment in LLC Geoilbent ("Geoilbent"(“Geoilbent”) and Arctic Gas Company ("(“Arctic Gas"Gas”), prior to the sale of our interests, based on a fiscal year ending September 30 (seeNote 2 -– Investments In and Advances to Affiliated Companies)Companies).
REVENUE RECOGNITION
Reporting and Functional Currency
The U.S. dollar is our functional and reporting currency.
Revenue Recognition
Oil and natural gas revenue is accrued monthly based on production and delivery. Each quarter, Benton-Vinccler invoices PDVSAPetroleos 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 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 EQUIVALENTSEach quarter, Benton-Vinccler also invoices PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production (“Incremental Crude Oil”). A portion of the Incremental Crude Oil is invoiced to PDVSA quarterly at a fixed price of $7.00 per Bbl.
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
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
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
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Credit Risk and Operations
All of our total consolidated revenues relate to operations in Venezuela. During the year ended December 31, 2002,2003, our Venezuelan crude oil and gas production represented all of itsour 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'employers’ and workers'workers’ organizations, together with political and civic organizations began a national civic work stoppage, which has seriously affected many of the country'scountry’s economic activities, in particular, the oil industry. As a result of the strike, we were unable to deliver crude oil and S-7
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,February 5, 2003, the Venezuelan Government has closed foreign currency markets
and announced its intention to implementimplemented currency exchange controls aimed at restricting the convertibility of the Venezuelan Bolivar and the transfer of funds out of Venezuela. The Venezuelan Government hasset the exchange rate at 1,600 Bolivars for each U.S. dollar and created a new Currency Exchange Agency ("CADIVI") which will beis responsible for the administration of exchange controls. The closure ofOn February 6, 2004, the foreign currency markets has limited
Benton-Vinccler's abilityofficial exchange rate was adjusted to obtain1,920 Venezuelan 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.each U.S. dollar. 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
Derivatives and Hedging
Statement of 2002 to use aFinancial Accounting Standards No. 133, as amended, establishes accounting and reporting standards for 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
$23.00instruments 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.activities. In order for a derivative instrument to qualify for hedge accounting, there must have beenbe 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. All derivatives are recorded on the balance sheet at fair value. To the extent that the hedge is determined to be effective, changes in the fair value of derivatives for qualifying cash flow hedges are recorded each period in other comprehensive income. Our derivatives are cash flow hedge transactions in which we hedge the variability of cash flows related to forecasted transactions. These derivative instruments have been designated as a cash flow hedge and the changes in the fair value has been reported in other comprehensive income assuming the highly effective test was met, and have been reclassified to earnings in the period in which earnings are impacted by the variability of the cash flows of the hedged item. 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
Benton-Vinccler hedged a portion of Financial Accounting Standards No. 133, as amended, establishes
accounting and reporting standardsits 2003 oil sales by purchasing a WTI crude oil “put” to protect its 2003 cash flow. The put was for derivative instruments and hedging
activities. All derivatives are recorded on10,000 barrels of oil per day for the balance sheet at fair value. To
the extent that the hedge is determined to be effective, as discussed above,
changes in the fair valueperiod 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.March 1, 2003 through December 31, 2003. This derivative instrument was designated as a cash flow
hedge and the changes in the fair value will be reported in other comprehensive
income assumingput qualified under the highly effective testtest. Due to the pricing structure for our Venezuela oil, the put had the economic effect of hedging approximately 20,800 barrels of oil per day. The put cost is met,$2.50 per barrel, or $7.7 million, and has been reclassified to
earnings inhad a strike price of $30.00 per barrel. Settlements of $1.7 million as well as the period in which earnings are impacted by the variabilityamortization of the cash flowsput option cost of $7.7 million have been reflected as a net reduction to oil revenue.
Benton-Vinccler hedged a portion of its 2002 oil sales by purchasing a commodity contract (costless collar), which required payment to (or receipts from) counterparties based on a WTI floor price of $23.00 and a ceiling price of $30.15 for 6,000 barrels of oil per day. The collar qualified under the hedged item. Wehighly effective test. At December 31, 2002, 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 aan oil revenue reduction in the amount of $0.3 million.
The notional amount of each financial instrument is based on expected sales of crude oil production from existing and future development wells and the related incremental oil production associated with production from high gas-to-oil ratio wells after the installation of a gas pipeline. These instruments protect our projected investment return and cash flow derived from our production by reducing the impact of a downward crude oil price movement until their expiration.
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Asset Retirement Liability
Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). As a result of adopting this statement, Benton-Vinccler recorded under the full cost method of accounting for oil and gas properties an increase in oil and gas properties as well as a corresponding liability in the amount of $4.3 million. This asset retirement obligation is associated with the plugging and abandonment of certain wells in Venezuela. SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. Historically, we determined that there would be no wells to plug and abandon before returning the fields to PDVSA. In connection with this
instrumentJanuary 2003, one of our wells suffered a leak in its casing allowing natural gas to flow to the surface. The well was plugged and abandoned and a comprehensive study of all existing wells was undertaken. This study indicated an increased likelihood that we had deposited collateralwould have to plug and abandon certain of $1.8 million asthe wells during the term of the agreement. No prior provision was undertaken and no cumulative adjustment was required. We abandoned 11 wells in 2003. Changes in asset retirement obligations during the year ended December 31, 2002
with the counterparty.
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ACCOUNTS AND NOTES RECEIVABLE2003 were as follows: Asset retirement obligations as of January 1, 2003 $ — Liabilities recorded during the first quarter 4,237 Liabilities settled during the year (733 ) Revisions in estimated cash flows (2,125 ) Accretion expense 80
Asset retirement obligations as of December 31, 2003 $ 1,459
Accounts and Notes Receivable
Allowance for doubtful accounts related to former employee notes at December 31, 2003 and 2002 was $3.4 million and 2001 was $3.5 million, and $6.2 million, respectively (seeNote 13 -– Related Party Transactions)Transactions).
OTHER ASSETS
Other Assets
Other assets consist principally of costs associated with the issuance of long-term debt.debt and investigative costs associated with new projects. 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 EQUIPMENTNew project costs are reclassified to oil and gas properties or expensed depending on management’s assessment of the likely outcome of the project.
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.basis, subject to a cost center ceiling (as defined by the Securities and Exchange Commission [“SEC”]). 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 for the year ended December 31, 2001, and $1.5capitalized interest of $0.5 million and $0.9 million for the years ended December 31, 20012002 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 in 2003 and 2002, and no capitalized interest in 2002.2003. Only overhead that is directly identified with acquisition, exploration or development activities isare 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 regularlyAt least annually we 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 2003, 2002 and 2001, and 2000, the Companywe recognized $0.2 million, $14.5 million and $0.5 million, and $1.3 million,
respectively, of impairment expensein impairments associated with certainformer exploration activities.prospects and the China WAB-21 block. 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, 20022003 consisted of property acquisition costs in the following by yearamount of $2.9 million which were all incurred (in thousands):
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Statement of Financial Accounting Standards No. 141 – Business Combinations (“FAS 141”) and No. 142 – Goodwill and Other Intangible Assets (“FAS 142”) included new terminology on the disclosure of what constitutes an intangible asset. One interpretation being considered relative to these standards is that a mineral interest associated with proved and undeveloped oil and gas leasehold acquisition costs should be classified separately in Oil and Gas Properties on the Consolidated Balance Sheet as intangible assets, and the disclosures required by FAS 141 and FAS 142 would be included in the Notes to Financial Statements. We believe that the presentation and disclosure of the $2.9 million excluded costs attributed to the China cost center is appropriate pending further guidance on this matter.
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, 2003, 2002 and 2001 and 2000 was $19.6 million, $24.9 million and $22.1 million ($2.52, $2.56 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 $1.6 million, $1.4 million $3.4
million and $1.8$3.4 million for the years ended December 31, 2003, 2002 and 2001, and 2000,
respectively.
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The major components of property and equipment at December 31 are as follows (in thousands):
| 2003 | 2002 | |||||||
| Proved property costs | $ | 582,456 | $ | 566,415 | ||||
| Costs excluded from amortization | 2,900 | 2,900 | ||||||
| Material and supply inventories | 8,266 | 7,286 | ||||||
| Other administrative property | 8,948 | 7,503 | ||||||
| 602,570 | 584,104 | |||||||
| Accumulated depletion, impairment and depreciation | (418,507 | ) | (439,344 | ) | ||||
| $ | 184,063 | $ | 144,760 | |||||
We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the SecuritiesSEC. The consolidated financial statements of the wholly-owned and Exchange Commission.
Nomajority owned subsidiaries do not include ceiling test write-downs were required.
INCOME TAXESin 2003. Equity in Net Losses of Affiliated Companies includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ending September 30, 2003.
Stock-Based Compensation
At December 31, 2003 and 2002, we had several stock-based employee compensation plans, which are more fully described inNote 6 – Stock Option and Stock Purchase Plans. Prior to 2003, we accounted for those plans under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Effective January 1, 2003, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards Statement No. 123 (“FAS 123”), Accounting for Stock-Based Compensation, prospectively to all employee awards granted, modified, or settled after January 1, 2003. Awards under our plans vest in periodic installments after one year of their grant and expire ten years from grant date. Therefore, the costs related to stock-based employee compensation included in the determination of net income in the years ended December 31, 2003 and 2002 are less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of FAS 123. The following table illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period.
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| 2003 | 2002 | 2001 | ||||||||||
| Net income, as reported | $ | 27,303 | $ | 100,362 | $ | 43,237 | ||||||
| Add: Stock-based employee compensation cost, net of tax | 296 | 915 | 35 | |||||||||
| Less: Total stock-based employee compensation cost determined under fair value based method, net of tax | (1,056 | ) | (2,905 | ) | (2,459 | ) | ||||||
| Net income – proforma | $ | 26,543 | $ | 98,372 | $ | 40,813 | ||||||
| Net income per common share: | ||||||||||||
| Basic – as reported | $ | 0.77 | $ | 2.90 | $ | 1.27 | ||||||
| Basic – proforma | $ | 0.75 | $ | 2.87 | $ | 1.20 | ||||||
| Diluted – as reported | $ | 0.74 | $ | 2.78 | $ | 1.27 | ||||||
| Diluted – proforma | $ | 0.72 | $ | 2.75 | $ | 1.20 | ||||||
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 fourththird quarter of 2001,2003, a substantial portion of the valuation allowance was reversed based on the utilization of net operating losses which offset U.S. taxable income generated by the Arctic Gas Salesale of our minority equity investment in 2002.
FOREIGN CURRENCYGeoilbent.
Foreign Currency
We have significant operations outside of the United States, principally in Venezuela and, anuntil September 25, 2003, a minority equity investment in Russia. The U.S. dollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in United StatesU.S. dollars, and all currency gains or losses are recorded in the statement of income.operations. 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 currenciescurrency to the United StatesU.S. 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
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 doeswe do 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, which was due February 28, 2003, 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, 20022003 and 2001,2002, was approximately $85.0 million and $77.4 million, and $138.1
million, respectively.
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COMPREHENSIVE INCOME
Comprehensive Income
Statement of Financial Accounting Standards No. 130 ("(“SFAS 130"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 ofreflected unrealized mark-to-
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market gains/(losses) from cash flow hedging activities as other comprehensive incomeincome/(loss) during the three years ended December 31, 20022003 and in accordance with SFAS 130, have not provided a separate
statement of comprehensive income.
MINORITY INTERESTS2002.
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 from or added to arrive at consolidated net income.
NEW ACCOUNTING PRONOUNCEMENTS
New Accounting Pronouncements
In September 2001,May 2003, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting StandardsStandard No. 143, Accounting150 “Accounting for Asset Retirement
Obligations (SFAS No. 143)Certain Financial Instruments with Characteristics of both Liabilities and Equity” (the “Statement”). SFAS No. 143 requires entities to recordThe Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement is generally effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at 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 amountbeginning 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 yearsfirst interim period beginning after SeptemberJune 15, 2002. We will adopt
SFAS No. 143 effective January 1, 2003 and such2003. The adoption will not materially
impact the financial statements sinceof this Statement had no effect on 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,January 2003, the FASB issued SFASInterpretation No. 145, Recission46 (“FIN 46”) Consolidation of FASB Statements No. 4,
44, and 64, AmendmentVariable Interest Entities, which addresses the consolidation 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
coveredvariable interest entities (“VIEs”) by the standard include lease termination costs and certain employee
severance costsbusiness enterprises 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 forprimary beneficiaries. A VIE is 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:
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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,sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or FIN 46, "Consolidation of Variable
Interest Entities" was issued. FIN 46 identifies certain off-balance sheet
arrangements that meetwhose equity investors lack the definitioncharacteristics of a variable interest entity (VIE).controlling financial interest. The primary beneficiary of a VIE is the partyenterprise that is exposed tohas the majority of the risks and/or returns ofrewards associated with the VIE. In future accounting periods,December 2003, the primary
beneficiary will be requiredFASB issued a revision to consolidate the VIE. In addition, more extensive
disclosure requirements applyFIN 46, Interpretation No. 46R (“FIN 46R”), to the primary beneficiary, as well as other
significant investors. We do not believe we participate in any arrangement that
would be subject toclarify some of the provisions of FIN 46.
USE OF ESTIMATES46, and to defer certain entities from adopting until the end of the first interim or annual reporting period ending after March 15, 2004. Application of FIN 46R is required in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types of VIEs is required in financial statements for periods ending after March 15, 2004. We believe we have no arrangements that would require the application of FIN 46R. We have no material off-balance sheet arrangements.
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.
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RECLASSIFICATIONS
Reclassifications
Certain items in 20002001 and 20012002 have been reclassified to conform to the 20022003 financial statement presentation.
NOTE
Note 2 - INVESTMENTS IN AND ADVANCES TO AFFILIATED COMPANIES— Investments In and Advances To Affiliated Companies
On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited and Arctic Gas arerecognized a pre-tax gain on the sale of $46.6 million (seeNote 9 – Russian Operations). Prior to the sale, our 34 percent minority equity investment in Geoilbent was accounted for using the equity method due to the significant influence we exerciseexercised over their operations and management. Investments includeincluded amounts paid to the investee companiescompany 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.company. Equity in earnings of Geoilbent and Arctic Gas areis based on a fiscal year ending September 30. Arctic Gas was sold on April 12, 2002.No dividends have been paid to us from Geoilbent.
Equity in earnings and losses and investments in and advances to companies
accounted for using the equity methodGeoilbent are as follows (in thousands):
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| LLC Geoilbent | ||||||||
| 2003 | 2002 | |||||||
| Investments: | ||||||||
| In equity in net assets | $ | — | $ | 28,056 | ||||
| Other costs, net of amortization | — | (263 | ) | |||||
| Total investments | — | 28,319 | ||||||
| Advances | — | 2,527 | ||||||
| Equity in earnings | — | 20,937 | ||||||
| Total | $ | — | $ | 51,783 | ||||
Note 3 - LONG-TERM DEBT AND LIQUIDITY
LONG-TERM DEBT— Long-Term Debt and Liquidity
Long-Term Debt
Long-term debt consists of the following (in thousands):
| December 31, | December 31, | |||||||
| 2003 | 2002 | |||||||
| Senior unsecured notes with interest at 9.375% | ||||||||
| See description below | $ | 85,000 | $ | 85,000 | ||||
| Note payable with interest at 6.1% | ||||||||
| See description below | 2,700 | 3,900 | ||||||
| Note payable with interest at 39.7% | ||||||||
| See description below | — | 2,167 | ||||||
| Note payable with interest at 7.1% | 15,500 | 15,500 | ||||||
| 103,200 | 106,567 | |||||||
| Less current portion | 6,367 | 1,867 | ||||||
| $ | 96,833 | $ | 104,700 | |||||
In November 1997, we issued $115.0 million in 9.375 percent senior unsecured notes due November 1, 2007 ("(“2007 Notes"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, 2002,2003, 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
("LIBOR"(“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"(“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. The Bolivar loan was repaid as of Venezuela. The interest rate for the quarter
ending DecemberMarch 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.2003. The loans provide for certain limitations on mergers and sale of assets. The Company hasWe have guaranteed the repayment of this loan
Onloan.
In 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 90-day LIBOR plus 6 percentage points determined quarterly.points. 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'smillion beginning with the first quarter 2004 to coincide with the first payment from our gas sales.
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 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reducesreduced 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 valueterms of the long-term
portion2007 Notes require that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the settlement liability is $0.7 million at December 31, 2001. The
entire balance was repaid by December 31, 2002.sale, or any amount not so invested must be used to repay or prepay the 2007 Notes or certain debts of subsidiaries.
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The principal payment requirements for our long-term debt outstanding at December 31, 20022003 are as follows (in thousands):
| 2004 | $ | 6,367 | ||
| 2005 | 6,367 | |||
| 2006 | 5,466 | |||
| 2007 | 85,000 | |||
| $ | 103,200 | |||
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$139 million at December 31, 2002,2003, can be invested in other opportunities used to develop our significant proved undeveloped reserves or used to repurchase our outstanding debt.
NOTE
Note 4 - COMMITMENTS AND CONTINGENCIES— Commitments and Contingencies
We have employment contracts with fourfive 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.control. 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.
Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas. This suit was brought in May, 2003 by Excel alleging, among other things, breach of a consulting agreement between Excel and us, misappropriation of proprietary information and trade secrets, and fraud. Excel seeks actual and exemplary damages, injunctive relief and attorneys’ fees. The Company isCourt has abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.
We are a defendant in or otherwise involved in litigation incidental to itsour business. In the opinion of management, there is no litigation which is material to the Company.
NOTEus.
Note 5 - TAXES
TAXES OTHER THAN ON INCOME— 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 year ended December 31, 2002 included a non-recurring foreign payroll tax adjustment of $0.7 million. The components of taxes other than on income were (in thousands):
| 2003 | 2002 | 2001 | ||||||||||
| Venezuelan municipal taxes | $ | 2,741 | $ | 3,805 | $ | 4,447 | ||||||
| Franchise taxes | 341 | 139 | 121 | |||||||||
| Payroll and other taxes | 291 | 124 | 802 | |||||||||
| $ | 3,373 | $ | 4,068 | $ | 5,370 | |||||||
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Taxes on Income
The tax effects of significant items comprising our net deferred income taxes as of December 31, 20022003 and 20012002 are as follows (in thousands):
| 2003 | 2002 | |||||||
| Deferred tax assets: | ||||||||
| Operating loss carryforwards | $ | 20,442 | $ | 19,690 | ||||
| Difference in basis of property | 29,602 | 21,495 | ||||||
| Other | 3,070 | 2,043 | ||||||
| Valuation allowance | (48,365 | ) | (39,146 | ) | ||||
| Net deferred tax asset | $ | 4,749 | $ | 4,082 | ||||
The valuation allowance increased by $19.4$9.2 million as a result of the increasechange in the U.S. deferred tax assets related to the net operating loss carryforward.carryforward as well as a Venezuelan deferred tax asset impairment. 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 not be realized through future taxable income.
The components of income before income taxes and minority interest and
extraordinary items are as follows (in thousands):
| 2003 | 2002 | 2001 | ||||||||||
| Income (loss) before income taxes | ||||||||||||
| United States | $ | 21,812 | $ | 89,455 | $ | (26,572 | ) | |||||
| Foreign | 49,976 | 80,356 | 33,754 | |||||||||
| Total | $ | 71,788 | $ | 169,811 | $ | 7,182 | ||||||
The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
| 2003 | 2002 | 2001 | ||||||||||
| Current: | ||||||||||||
| United States | $ | 1,188 | $ | 353 | $ | 1 | ||||||
| Foreign | 9,136 | 6,324 | 6,700 | |||||||||
| $ | 10,324 | $ | 6,677 | $ | 6,701 | |||||||
| Deferred: | ||||||||||||
| United States | $ | — | $ | 53,413 | (42,405 | ) | ||||||
| Foreign | (667 | ) | 205 | 6 | ||||||||
| (667 | ) | 53,618 | (42,399 | ) | ||||||||
| $ | 9,657 | $ | 60,295 | $ | (35,698 | ) | ||||||
During 2003, we reduced our foreign tax provision approximately $3.9 million related to the resolution of certain prior year foreign income tax matters. Additionally, we recorded a domestic tax provision of approximately $1.1 million related to certain domestic tax matters identified during the year.
A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):
| 2003 | 2002 | 2001 | ||||||||||
| Computed tax expense at the statutory rate | $ | 15,025 | $ | 59,348 | 4,580 | |||||||
| State income taxes | 1,188 | 353 | — | |||||||||
| Effect of foreign source income and rate differentials on foreign income | (15,849 | ) | (19,373 | ) | 1,675 | |||||||
| Change in valuation allowance | 9,219 | 19,446 | (53,413 | ) | ||||||||
| Prior year adjustments | — | — | 2,304 | |||||||||
| Reclass paid-in capital | — | — | 11,007 | |||||||||
| All other | 74 | 80 | 215 | |||||||||
| Sub-total income tax expense (benefit) | 9,657 | 59,854 | (33,632 | ) | ||||||||
| Effects of recording equity income of certain affiliated Companies on an after-tax basis | — | 441 | (2,066 | ) | ||||||||
| Total income tax expense (benefit) | $ | 9,657 | $ | 60,295 | $ | (35,698 | ) | |||||
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.
S-15
At December 31, 2002,2003, we had, for federal income tax purposes, operating loss carryforwards of approximately $56.3$58.4 million, expiring in the years 20112018 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
Note 6 - STOCK OPTION AND STOCK PURCHASE PLANS— Stock Option and Stock Purchase Plans
In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the "Stock“Stock Purchase Plan"Plan”) to encourage our directors to acquire a greater proprietary interest in our companyus 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'sdirector’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 Incentive Stock Options and Non-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
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.
Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 Long Term Stock Incentive Plan, no options may be granted under any of these plans.
A summary of the status of our stock option plans as of December 31, 2003, 2002 2001
and 20002001 and changes during the years ending on those dates is presented below (shares in thousands):
| 2003 | 2002 | 2001 | ||||||||||||||||||||||
| Weighted | Weighted | Weighted | ||||||||||||||||||||||
| Average | Average | Average | ||||||||||||||||||||||
| Exercise | Exercise | Exercise | ||||||||||||||||||||||
| Price | Shares | Price | Shares | Price | Shares | |||||||||||||||||||
| Outstanding at beginning of the year: | $ | 7.42 | 5,223 | $ | 6.36 | 6,865 | 7.74 | 5,660 | ||||||||||||||||
| Options granted | 6.26 | 246 | 4.84 | 165 | 1.65 | 1,684 | ||||||||||||||||||
| Options exercised | 2.32 | (494 | ) | 2.21 | (1,515 | ) | — | — | ||||||||||||||||
| Options cancelled | 11.37 | (452 | ) | 8.03 | (292 | ) | 6.43 | (479 | ) | |||||||||||||||
| Outstanding at end of the year | 7.52 | 4,523 | 7.42 | 5,223 | 6.36 | 6,865 | ||||||||||||||||||
| Exercisable at end of the year | 8.18 | 3,857 | 8.49 | 4,360 | 8.32 | 4,800 | ||||||||||||||||||
Significant option groups outstanding at December 31, 20022003 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, 2003 | Contractual Life | Exercise Price | December 31, 2003 | Exercise Price | |||||||||||||||||||||||
| $ | 1.55 | - | $ | 2.75 | 2,027,150 | 5.91 | $ | 1.97 | 1,679,983 | $ | 2.03 | |||||||||||||||||
| $ | 4.80 | - | $ | 7.00 | 621,000 | 4.69 | 5.81 | 337,667 | 5.87 | |||||||||||||||||||
| $ | 7.25 | - | $ | 11.00 | 488,633 | 1.69 | 8.77 | 452,633 | 8.90 | |||||||||||||||||||
| $ | 11.50 | - | $ | 16.50 | 946,665 | 1.42 | 13.52 | 946,665 | 13.52 | |||||||||||||||||||
| $ | 17.38 | - | $ | 24.13 | 439,833 | 1.78 | 21.21 | 439,833 | 21.21 | |||||||||||||||||||
| 4,523,281 | 3,856,781 | |||||||||||||||||||||||||||
S-16
Of the number outstanding, 1,233,7501,108,750 options are controlled by the companyus through the A. E. Benton settlement. SeeNote 13 -– Related Party Transactions.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'sCompany’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, 2002,2003, 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 our officers, directors or employees of the Company at prices ranging from $5.63 to $11.88 which vest over three to four years. At December 31, 2002,2003, a total of 192,50061,000 options issued outside of the plans were both outstanding and exercisable.
S-17
NOTE
Note 7 - STOCK WARRANTS— 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, 20022003 were (warrants in thousands):
| Warrants | ||||||||||||||
| Date Issued | Expiration Date | Exercise Price | Issued | Outstanding | ||||||||||
| July 1994 | July 2004 | $ | 7.50 | 150 | 8 | |||||||||
| December 1994 | December 2004 | 12.00 | 50 | 50 | ||||||||||
| June 1995 | June 2007 | 17.09 | 125 | 125 | ||||||||||
| 325 | 183 | |||||||||||||
Note 8 - OPERATING SEGMENTS— Operating Segments
We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities. Revenue from Venezuela is derived primarily from the production and sale of oil.oil and gas. Other income from USA and otherOther is derived primarily from interest earnings on various investments and consulting revenues. Operations included under the heading "USA“USA and Other"Other” include corporate management, exploration activities, cash management and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the USA and Other segment and are not allocated to other operating segments.
S-17
Year ended December 31, 2003:
| (in thousands) | Venezuela | USA and Other | Russia | Eliminations | Consolidated | |||||||||||||||
| Revenues | ||||||||||||||||||||
| Oil sales | $ | 103,920 | $ | — | $ | — | $ | — | $ | 103,920 | ||||||||||
| Gas sales | 2,740 | — | — | — | 2,740 | |||||||||||||||
| Ineffective hedge activity | (565 | ) | — | — | — | (565 | ) | |||||||||||||
| 106,095 | — | — | — | 106,095 | ||||||||||||||||
| Expenses | ||||||||||||||||||||
| Operating expenses | 31,309 | 76 | (492 | ) | — | 30,893 | ||||||||||||||
| Depletion, depreciation and amortization | 21,035 | 109 | 44 | — | 21,188 | |||||||||||||||
| General and administrative | 4,031 | 10,514 | 1,201 | — | 15,746 | |||||||||||||||
| Arbitration settlement | — | 1,477 | — | — | 1,477 | |||||||||||||||
| Bad debt recovery | — | (374 | ) | — | — | (374 | ) | |||||||||||||
| Taxes other than on income | 2,921 | 447 | 5 | — | 3,373 | |||||||||||||||
| Total expenses | 59,296 | 12,249 | 758 | — | 72,303 | |||||||||||||||
| Income (loss) from operations | 46,799 | (12,249 | ) | (758 | ) | — | 33,792 | |||||||||||||
| Other non-operating income (expense) | ||||||||||||||||||||
| Gain on disposition of assets | — | 46,619 | — | — | 46,619 | |||||||||||||||
| Investment earnings and other | 435 | 983 | — | — | 1,418 | |||||||||||||||
| Interest expense | (1,944 | ) | (8,470 | ) | — | 9 | (10,405 | ) | ||||||||||||
| Net gain on exchange rates | 495 | 34 | — | — | 529 | |||||||||||||||
| Intersegment revenues (expenses) | (7,484 | ) | 7,484 | — | — | — | ||||||||||||||
| Equity in losses of affiliated companies | — | — | (28,860 | ) | — | (28,860 | ) | |||||||||||||
| (8,498 | ) | 46,650 | (28,860 | ) | 9 | 9,301 | ||||||||||||||
| Income (loss) before income taxes | 38,301 | 34,401 | (29,618 | ) | 9 | 43,093 | ||||||||||||||
| Income tax expense | 8,459 | 1,187 | 2 | 9 | 9,657 | |||||||||||||||
| Operating segment income (loss) | 29,842 | 33,214 | (29,620 | ) | — | 33,436 | ||||||||||||||
| Write-downs of oil and gas properties and impairments | — | (165 | ) | — | — | (165 | ) | |||||||||||||
| Minority interest | (5,968 | ) | — | — | — | (5,968 | ) | |||||||||||||
| Net income (loss) | $ | 23,874 | $ | 33,049 | $ | (29,620 | ) | $ | — | $ | 27,303 | |||||||||
| Total assets | $ | 241,855 | $ | 180,768 | $ | 237 | $ | (48,512 | ) | $ | 374,348 | |||||||||
| Additions to properties | $ | 60,589 | $ | 245 | $ | 91 | $ | — | $ | 60,925 | ||||||||||
Year ended December 31, 2002
| (in thousands) | Venezuela | USA and Other | Russia | Eliminations | Consolidated | |||||||||||||||
| Revenues | ||||||||||||||||||||
| Oil sales | $ | 127,015 | $ | — | $ | — | $ | — | $ | 127,015 | ||||||||||
| Ineffective hedge activity | (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 disposition of assets | — | 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-downs 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............................... $ 122,386 $ - $ - $ - $ 122,386
----------- ---------- ------------ --------- ---------
Expenses
Operating expenses...................... 42,037 55 667 - 42,759
Depletion, depreciation and
amortization.......................... 22,096 3,408 12 - 25,516
General and administrative.............. 4,151 14,972 949 - 20,072
Taxes other than on income.............. 4,666 704 - - 5,370
----------- ---------- ------------ --------- ---------
Total expenses.................... 72,950 19,139 1,628 - 93,717
----------- ---------- ------------ --------- ---------
Income (loss) from operations............... 49,436 (19,139) (1,628) - 28,669
Other non-operating income (expense):
Investment earnings and other........... 5,995 2,053 60 (5,020) 3,088
Interest expense........................ (7,403) (22,695) - 5,223 (24,875)
Net gain on exchange rates.............. 732 36 - - 768
Intersegment revenues (expenses)........ (14,983) 14,983 - - -
Equity in income of affiliated
companies............................. - - 5,902 - 5,902
----------- ---------- ------------ --------- ---------
(15,659) (5,623) 5,962 203 (15,117)
----------- ---------- ------------ --------- ---------
Income (loss) before income taxes........... 33,777 (24,762) 4,334 203 13,552
Income tax (benefit) expense ............... 6,491 (42,392) - 203 (35,698)
----------- ---------- ------------ --------- ---------
Operating segment income.................... 27,286 17,630 4,334 - 49,250
Write-down of oil and gas properties and
impairments............................... - (468) - - (468)
Minority interest........................... (5,545) - - - (5,545)
----------- ---------- ------------ --------- ---------
Net income.................................. $ 21,741 $ 17,162 $ 4,334 $ - $ 43,237
=========== ========== ============ ========= =========
Total assets................................ $ 167,671 $ 165,254 $ 100,801 $ (85,575) $ 348,151
=========== ========== ============ ========= =========
Additions to properties..................... $ 43,411 $ - $ 31 $ - $ 43,442
=========== ========== ============ ========= =========
YEAR ENDED DECEMBER 31, 2000:
(in thousands) VENEZUELA USA AND OTHER RUSSIA ELIMINATIONS CONSOLIDATED
----------- ------------- ------------ ------------ ------------
Revenues
Oil and natural gas sales............... $ 139,890 $ 394 $ - $ - $ 140,284
----------- ---------- ------------ --------- ---------
139,890 394 - - 140,284
----------- ---------- ------------ --------- ---------
Expenses
Operating expenses...................... 46,727 59 644 - 47,430
Depletion, depreciation and
amortization.......................... 16,285 879 11 - 17,175
General and administrative.............. 3,659 12,014 1,066 - 16,739
Taxes other than on income.............. 3,355 1,048 (13) - 4,390
----------- ---------- ------------- --------- ---------
Total expenses.................... 70,026 14,000 1,708 - 85,734
----------- ---------- ------------ --------- ---------
Income (loss) from operations............... 69,864 (13,606) (1,708) - 54,550
Other non-operating income (expense):
Investment earnings and other........... 1,392 8,986 - (1,819) 8,559
Interest expense........................ (6,131) (24,661) - 1,819 (28,973)
Net gain on exchange rates.............. 298 28 - - 326
Intersegment revenues (expenses)........ (12,226) 12,226 - - -
Equity in income of affiliated
companies............................. - - 5,313 - 5,313
----------- ---------- ------------ --------- ---------
(16,667) (3,421) 5,313 - (14,775)
------------ ----------- ------------ --------- ---------
Income (loss) before income taxes........... 53,197 (17,027) 3,605 - 39,775
Income tax expense ......................... 14,020 12 - - 14,032
----------- ---------- ------------ --------- ---------
Operating segment income (loss)............. 39,177 (17,039) 3,605 - 25,743
Write-down of oil and gas properties and
impairments............................... - (1,346) - - (1,346)
Minority interest........................... (7,869) - - - (7,869)
Extraordinary income on debt repurchase..... - 3,960 - - 3,960
----------- ---------- ------------ --------- ---------
Net income (loss)........................... $ 31,308 $ (14,425) $ 3,605 $ - $ 20,488
=========== ========== ============ ========= =========
Total assets................................ $ 166,462 $ 156,780 $ 78,406 $(115,201) $ 286,447
=========== ========== ============ ========= =========
Additions to properties..................... $ 54,112 $ 3,075 $ 9 $ - $ 57,196
=========== ========== ============ ========= =========
NOTE
Year ended December 31, 2001:
| (in thousands) | Venezuela | USA and Other | Russia | Eliminations | Consolidated | |||||||||||||||
| Revenues | ||||||||||||||||||||
| Oil sales | $ | 122,386 | $ | — | $ | — | $ | — | $ | 122,386 | ||||||||||
| Expenses | ||||||||||||||||||||
| Operating expenses | 42,037 | 55 | 667 | — | 42,759 | |||||||||||||||
| Depletion, depreciation and amortization | 22,096 | 3,408 | 12 | — | 25,516 | |||||||||||||||
| General and administrative | 4,151 | 14,972 | 949 | — | 20,072 | |||||||||||||||
| Taxes other than on income | 4,666 | 704 | — | — | 5,370 | |||||||||||||||
| Total expenses | 72,950 | 19,139 | 1,628 | — | 93,717 | |||||||||||||||
| Income (loss) from operations | 49,436 | (19,139 | ) | (1,628 | ) | — | 28,669 | |||||||||||||
| Other non-operating income (expense): | ||||||||||||||||||||
| Investment earnings and other | 5,995 | 2,053 | 60 | (5,020 | ) | 3,088 | ||||||||||||||
| Interest expense | (7,403 | ) | (22,695 | ) | — | 5,223 | (24,875 | ) | ||||||||||||
| Net gain on exchange rates | 732 | 36 | — | — | 768 | |||||||||||||||
| Intersegment revenues (expenses) | (14,983 | ) | 14,983 | — | — | — | ||||||||||||||
| Equity in income of affiliated companies | — | — | 5,902 | — | 5,902 | |||||||||||||||
| (15,659 | ) | (5,623 | ) | 5,962 | 203 | (15,117 | ) | |||||||||||||
| Income (loss) before income taxes | 33,777 | (24,762 | ) | 4,334 | 203 | 13,552 | ||||||||||||||
| Income tax (benefit) expense | 6,491 | (42,392 | ) | — | 203 | (35,698 | ) | |||||||||||||
| Operating segment income | 27,286 | 17,630 | 4,334 | — | 49,250 | |||||||||||||||
| Write-down of oil and gas properties and impairments | — | (468 | ) | — | — | (468 | ) | |||||||||||||
| Minority interest | (5,545 | ) | — | — | — | (5,545 | ) | |||||||||||||
| Net income | $ | 21,741 | $ | 17,162 | 4,334 | — | $ | 43,237 | ||||||||||||
| Total assets | $ | 167,671 | $ | 165,254 | $ | 100,801 | $ | (85,575 | ) | $ | 348,151 | |||||||||
| Additions to properties | $ | 43,411 | $ | — | $ | 31 | $ | — | $ | 43,442 | ||||||||||
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Note 9 - RUSSIAN OPERATIONS
GEOILBENT
We ownRussian Operations
Geoilbent
On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus the repayment of the subordinated loan and certain payables owed to us by Geoilbent in the amount of $5.5 million. Prior to the sale, we owned 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 fieldsFields in the WestWestern Siberia region of Russia. Our minority equity investment in Geoilbent iswas accounted for using the equity method.method and was based on a fiscal year ending September 30. Sales quantities attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the years ended September 30, 2002 and 2001 were 5.6 million barrels (3.3 million domestic and 2000 were2.3 million export), 6.9 million Bbls,barrels (4.6 million domestic and 2.3 million export) and 5.2 million Bbls,barrels (0.8 million domestic and 4.4 million export) and 4.2
million Bbls,, respectively.
S-19
2000
averaged$23.05 export), $13.25 ($8.89 domestic and $21.73 export), and $19.51 ($13.69 domestic and $20.48 export) and $18.56 per barrel, respectively. Depletion expense attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the years ended September 30, 2002 and 2001 was $3.23, $3.93 and 2000
was $3.93, $2.88 and $2.25 per barrel, respectively. All amounts represent 100 percent of Geoilbent. Summarized financial information for Geoilbent follows (in thousands). All amounts represent 100
percent of Geoilbent.
Year ended September 30: 2002 2001 2000
----------- ----------- -----------
Revenues
Oil sales.................................................... $ 91,598 $ 101,159 $ 78,805
----------- ----------- -----------
Expenses
Selling and distribution expenses............................ 6,696 9,876 4,612
Operating expenses........................................... 15,360 11,415 8,959
Depletion, depreciation and amortization..................... 27,168 14,918 9,556
General and administrative................................... 8,335 5,650 3,407
Taxes other than on income................................... 27,657 26,011 18,286
----------- ----------- -----------
85,216 67,870 44,820
----------- ----------- -----------
Income from operations........................................... 6,382 33,289 33,985
Other non-operating income (expense)
Investment earnings and other................................ 381 648 (724)
Interest expense............................................. (4,629) (7,547) (7,438)
Net gain (loss) on exchange rates............................ 2,053 781 (597)
----------- ----------- -----------
(2,195) (6,118) (8,759)
----------- ----------- -----------
Income before income taxes....................................... 4,187 27,171 25,226
Income tax expense............................................... 302 6,751 6,321
----------- ----------- -----------
Net income ...................................................... $ 3,885 $ 20,420 $ 18,905
=========== =========== ===========
AT SEPTEMBER 30:
Current assets................................................... $ 18,785 $ 35,447 $ 30,979
Other assets..................................................... 186,815 187,706 163,332
Current liabilities.............................................. 54,051 60,439 36,567
Other liabilities................................................ 7,500 22,550 38,000
Net equity....................................................... 144,049 140,164 119,744
The European Bank for Reconstruction and Development ("EBRD") and
International Moscow Bank ("IMB") together 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 agreements, the Company and Minley are each jointly and severally liable
to EBRD for any losses, damages, liabilities, costs, expenses and other amounts
suffered or sustained arising out of any breach by the other of its support
obligations. As available, proceeds from the restructured loan will be used to
reduce payables and to develop the South Tarasovskoye Field.
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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 an event of default
whereby EBRD may, at its option, demand payment of the outstanding principal and
interest. In addition, the restructured loan agreement requires that Geoilbent
implement 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 interest.
At September 30, 2002, and September 30, 2001, the current liabilities
of Geoilbent exceeded its current assets by $35.3 million and $25.7 million,
respectively. Included in current liabilities as of September 30, 2002 are loans
repayable to EBRD ($22.0 million) and IMB ($0.6 million). This debt has been
classified as current because Geoilbent will 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 their
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 terms of the EBRD loan.
Geoilbent management plans to further address the 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. At December 31, 2002, Geoilbent
had accounts payable outstanding of $12.2 million of which approximately $5.9
million was 90 days or more past due. The amounts outstanding were primarily to
contractors and vendors for drilling and construction services. Under Russian
law, creditors, to whom payments are 90 days or more past due, can force a
company into involuntary bankruptcy. Geoilbent's financial statements do not
include any adjustments that might result if Geoilbent were unable to continue
as a going concern.: 2003 2002 2001 Revenues Oil sales $ 81,724 $ 91,598 $ 101,159
Expenses Selling and distribution expenses 5,893 6,696 9,876 Operating expenses 15,897 15,360 11,415 Depletion, depreciation and amortization 18,182 27,168 14,918 Write-downs of oil and gas properties 95,000 — — General and administrative 9,456 8,335 5,650 Taxes other than on income 25,626 27,657 26,011
170,054 85,216 67,870
Income (loss) from operations (88,330 ) 6,382 33,289 Other non-operating income (expense) Investment earnings and other 1,064 381 648 Interest expense (1,992 ) (4,629 ) (7,547 ) Net gain on exchange rates 1,566 2,053 781
638 (2,195 ) (6,118 )
Income (loss) before income taxes (87,692 ) 4,187 27,171 Income tax expense (3,117 ) 302 6,751
(84,575 ) 3,885 20,420 Effects of change in accounting policy 310 — —
Net income (loss) $ (84,885 ) $ 3,885 $ 20,420
Current assets $ 18,785 $ 35,447 Other assets 186,815 187,706 Current liabilities 54,051 60,439 Other liabilities 7,500 22,550 Net equity 144,049 140,164
As of September 30, 2002, the Geoilbent ($2.5 million from Harvest and
$5.0 million from Minley) shareholders had provided Geoilbent with subordinatedsubordinate loans totaling $7.5 million.million ($2.5 million from us). These loans arewere unsecured, and repayable commencing
in January 2004. Our interest rate is based on LIBOR up to January 2004 and rises from 8 torecorded as a current liability at September 30, 2003. The loan by us was repaid as part of the sale of our minority equity investment in Geoilbent. As of January 1, 2003, the Russian economy was no longer a highly inflationary economy. As a result, the Russian Ruble became the functional currency and not the U.S. dollar.
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Arctic Gas Company
On April 12, percent thereafter. There can be no assurance that Geoilbent
will have the ability to repay the loan made by the Company when due.
ARCTIC GAS COMPANY
In April 1998,2002, we signed an agreement to earn a 40sold our 68 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. We received voting shares representing 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. From December 1998 through December 31,
2001, we purchased shares representing an additional 28 percent equity interest
not subject to any sale or transfer restrictions. On April 12, 2002, we
concluded the Arctic Gas
S-21
Sale and transferred our 68 percent equity interest to the buyer.Gas. The equity earnings of Arctic Gas have historically been based on a calendarfiscal year ended September 30. The fourth quarter of 2001, the first quarter of 2002 and the first twelve days of April have been included in the results for 2002.
We accountaccounted for our interest in Arctic Gas using the equity method due to the significant influence we exerciseexercised over the operating and financial policies of Arctic Gas. Our weighted-average equity interest, not subject to any
sale or transfer restrictions for the yearsyear ended December 31, 2002, 2001 and
2000 was 49 percent, 39 percent and 29 percent, respectively.percent. We recorded as our share in the losses of Arctic Gas $1.5 million $1.1 million and $0.7$1.1 million for the period ended April 12, 2002 and September 30, 2001, and 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.
| 2002 | 2001 | |||||||
Year ended September 30: | ||||||||
| Revenues | ||||||||
| Oil Sales | $ | 7,880 | $ | 13,374 | ||||
| Expenses | ||||||||
| Selling and distribution expenses | 3,170 | 3,867 | ||||||
| Operating expense | 2,473 | 3,483 | ||||||
| Depletion, depreciation and amortization | 333 | 1,032 | ||||||
| General and administrative | 2,112 | 3,025 | ||||||
| Taxes other than on income | 1,261 | 3,881 | ||||||
| 9,349 | 15,288 | |||||||
| Loss from operations | (1,469 | ) | (1,914 | ) | ||||
| Other non-operating income (expense) | ||||||||
| Other income (expense) | (4 | ) | 54 | |||||
| Interest and foreign exchange expense | (1,722 | ) | (1,848 | ) | ||||
| (1,726 | ) | (1,794 | ) | |||||
| Loss before income taxes | (3,195 | ) | (3,708 | ) | ||||
| Income tax expense | — | — | ||||||
| Net loss | $ | (3,195 | ) | $ | (3,708 | ) | ||
Note 10 - VENEZUELA OPERATIONSVenezuela Operations
On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. ("Vinccler"(“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
In 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 daycommenced in the fourth quarter of 2003 and gradually increase up to 70 MMcfpd in 12 to 18 months
from the initial sale.2003. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production 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 2006.2005.
S-21
The Venezuelan government maintains full ownership of all hydrocarbons in the fields.
We drilled eleventhree oil wells and converted two watergas injection wells to producing wells in 2002.
NOTE2003.
Note 11 - UNITED STATES OPERATIONS
We had a 35 percent working interest in the Lakeside Exploration Prospect,
Cameron Parish, Louisiana. In September 2002, we determined that the Claude
Boudreaux #1 exploratory well was not prospective for hydrocarbons and assigned
our entire interest in the Lakeside Exploration Prospect to a third party. We
recognized $1.1 million impairment in the three months ended September 30, 2002.United States Operations
We acquired a 100 percent interest in three California State offshore oil and gas leases ("(“California Leases"Leases”) and a parcel of onshore property from Molino Energy Company, LLC. We impaired all of theAll 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.have been fully impaired. The Company has determined
that it will not pursue further development of the California Leases have expired and will
plug and abandonwe have listed the previously drilled exploratory well, and undertake any
required lease and land reclamation. It is believed that these costs will not be
material.
NOTEonshore property for sale.
Note 12 - CHINA OPERATIONSChina Operations
In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation ("CNOOC"(“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'sPeople’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same 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 under dispute. As part of oura review of companyour assets, wea third-party conducted a third-partyan 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. An evaluation was performed again at December 31, 2003 and such evaluation indicated that no further impairment of the property had been incurred in 2003. WAB-21 represents the $2.9 million excluded from the full cost pool as reflected on our December 31, 20022003 balance sheet.
S-23
NOTE
Note 13 - RELATED PARTY TRANSACTIONSRelated Party Transactions
We have entered into construction service agreements with Venezolana International, S.A. (“Vinsa”). Vinsa is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Benton-Vinccler. Vinsa has provided $1.7 million, $0.5 million and $0.6 million in construction services on our Venezuelan gas pipeline and field operations for the years ended December 31, 2003, 2002 and 2001, respectively.
We have entered into a consulting agreement with Oil & Gas Technology Consultants Inc. (“OGTC”) to provide operational and technical assistance in Venezuela. OGTC is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Benton-Vinccler. Payment for services is due when earnings are not reinvested in Benton-Vinccler operations. Expenses related to this consulting agreement was $1.5 million, $2.6 million and $2.5 million at December 31, 2003, 2002 and 2001, respectively.
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'sBenton’s shares of our 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 with Mr. Benton pursuant to which we retained Mr. Benton under a consulting agreement to perform certain services for us. In 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 a total of $536,545 from February 2000
through May 2001 for services performed under the consulting agreement, and inIn June 2002, we made an estimated incentive bonus payment to Mr. Benton of $1.5 million, subject to future adjustment, in connection with the Arctic Gas Sale which wesale. We recorded the bonus payment as a reduction of the gain on the Arctic Gas Sale.
On May 11, 2001,sale. In November 2003, we made a payment to Mr. Benton of $0.5 million for the incentive bonus associated with the sale of our minority equity investment in Geoilbent.
In May 2001, we and the CompanyMr. Benton 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 providesprovided for the repayment of our loans to him. In March 2002, Mr. Benton filed a plan of reorganization, in his bankruptcy case which
incorporated the terms of the settlement agreement. Onand on July 31, 2002, the bankruptcy court confirmed the plan of reorganization, andreorganization. At the ordertime the plan became final, Mr. Benton’s indebtedness to become
final on August 10, 2002. As of that date, Mr. Benton's indebtednessus was about $6.7 million for which we provided a full reserve.allowance for bad debt. On August 14, 2002, we exercised our rights with respect to 600,000 shares of our stock in the Company pledged to us as partial repayment of the loan and took the shares into the Company asour 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 September 2002 and July 2003, we received a
paymentpayments of about $1.1approximately $1.3 million as a partial distributiondistributions from Mr. Benton's
S-22
Benton’s debtor-in-possession account. Finally, under the terms of the settlement agreement, we have retained about $0.1$0.2 million from the Arctic Gas and Geoilbent bonus paymentpayments to Mr. Benton, for abringing the total recovery of $3.3on Mr. Benton’s debt to $3.7 million. We continue to accrue interest and provide a reservebad debt allowance on the remaining 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 stockIn addition, we
acquired from Mr. Benton. We are due the balance of this account as the expenses
and tax liabilities are finally determined. We also hold the rights to direct the exercise of Mr. Benton'sBenton’s stock options.
We and Mr. Benton and the Company disagreedisagreed over Mr. Benton'sBenton’s remaining obligations to us under the settlement agreement and plan of reorganization. In addition, Mr. Benton is claimingclaimed that he iswas due significant additional amounts with respect to the incentive bonus associated with the Arctic Gas Sale.sale. We and Mr. Benton and the
Company have agreed to submit theirsubmitted our dispute to binding arbitration. Whilearbitration and in October 2003 the outcomearbitrator found in favor of arbitration cannot be predicted,Mr. Benton in all material respects. As a result, in October 2003, we believe that we havemade a substantial basispayment to Mr. Benton of $1.9 million for our positionsthe balance of the incentive bonus associated with the Arctic Gas sale and intendreleased certain funds for the payment of Mr. Benton’s taxes and expenses related to vigorously pursue them.
NOTEthe disposition of his 600,000 shares of stock.
Note 14 - EARNINGS PER SHAREEarnings Per Share
Basic earnings per common share ("EPS"(“EPS”) isare 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 35.3 million, 34.6 million 34.0 million and 30.733.9 million for the years ended December 31, 2003, 2002 2001 and 2000,2001, 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 36.8 million, 36.1 million 34.0 million
and 30.934.0 million for the years ended December 31, 2003, 2002 and 2001, and 2000,
respectively.
An aggregate of 3.52.5 million options and warrants were excluded from the earnings per share calculations because their exercise price exceeded the average share
price duringthey were anti-dilutive for the year ended December 31, 2002.2003. For the years ended December 31, 2002 and 2001, and 2000, 6.73.5 million and 5.66.7 million options and warrants, respectively, were excluded from the earnings per share calculations because they were anti-dilutive.
NOTE 15 - SUBSEQUENT EVENT
Benton-Vinccler has 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.
S-24
S-23
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data (unaudited)
Summarized quarterly financial data is as follows:
| Quarter Ended | ||||||||||||||||
| March 31 | June 30 | September 30 | December 31 | |||||||||||||
| (amounts in thousands, except per share data) | ||||||||||||||||
Year ended December 31, 2003 | ||||||||||||||||
| Revenues | $ | 18,825 | $ | 28,576 | $ | 27,834 | $ | 30,860 | ||||||||
| Expenses | (13,901 | ) | (19,911 | ) | (20,037 | ) | (18,619 | ) | ||||||||
| Non-operating income (expense) | (1,864 | ) | (2,288 | ) | 44,056 | (1,743 | ) | |||||||||
| Income from consolidated companies before income taxes and minority interests | 3,060 | 6,377 | 51,853 | 10,498 | ||||||||||||
| Income tax expense | 1,056 | 3,104 | 3,603 | 1,894 | ||||||||||||
| Income before minority interests | 2,004 | 3,273 | 48,250 | 8,604 | ||||||||||||
| Minority interests | 887 | 1,216 | 1,367 | 2,498 | ||||||||||||
| Income from consolidated companies | 1,117 | 2,057 | 46,883 | 6,106 | ||||||||||||
| Equity in net income (losses) of affiliated companies | (16,575 | ) | (13,470 | ) | (473 | ) | 1,658 | |||||||||
| Net income (loss) | $ | (15,458 | ) | $ | (11,413 | ) | $ | 46,410 | $ | 7,764 | ||||||
| Other comprehensive income (loss) | 2,614 | (3,001 | ) | 21 | 366 | |||||||||||
| Total comprehensive income (loss) | $ | (12,844 | ) | $ | (14,414 | ) | $ | 46,431 | $ | 8,130 | ||||||
| Net income (loss) per common share: | ||||||||||||||||
| Basic | $ | (0.44 | ) | $ | (0.32 | ) | $ | 1.31 | $ | 0.22 | ||||||
| Diluted | $ | (0.44 | ) | $ | (0.32 | ) | $ | 1.25 | $ | 0.21 | ||||||
| Quarter Ended | ||||||||||||||||
| March 31 | June 30 | September 30 | December 31 | |||||||||||||
| (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 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 before minority interests | 2,778 | 80,523 | 13,497 | 12,718 | ||||||||||||
| Minority interests | 1,380 | 2,031 | 2,590 | 3,318 | ||||||||||||
| Income from consolidated companies | 1,398 | 78,492 | 10,907 | 9,400 | ||||||||||||
| Equity in net income (losses) of affiliated companies | 87 | (2,172 | ) | 1,209 | 1,041 | |||||||||||
| Net income | $ | 1,485 | $ | 76,320 | $ | 12,116 | $ | 10,441 | ||||||||
| Other comprehensive loss | — | — | (658 | ) | 658 | |||||||||||
| Total comprehensive income | 1,485 | 76,320 | 11,458 | 11,099 | ||||||||||||
| Net income per common share: | ||||||||||||||||
| Basic | $ | 0.04 | $ | 2.20 | $ | 0.35 | $ | 0.30 | ||||||||
| Diluted | $ | 0.04 | $ | 2.10 | $ | 0.33 | $ | 0.28 | ||||||||
In the second quarter of 2002, we recognized in non-operating income, the $140.2$144.0 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
S-24
Supplemental Information on Oil and Natural Gas Sale in 2002.
S-25
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)Producing Activities (unaudited)
In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures“Disclosures About Oil and Gas Producing Activities" ("Activities” (“SFAS 69"69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
TABLE I - TOTAL COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION,
EXPLORATION AND DEVELOPMENT ACTIVITIES (IN THOUSANDS)Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
UNITED STATES
VENEZUELA CHINA AND OTHER TOTAL
--------- --------- ------------- ---------
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 $ 35,194 $ 77 $ 28 $ 35,299
Exploration costs 7,694 - 909 8,603
--------- --------- --------- ---------
$ 42,888 $ 77 $ 937 $ 43,902
========= ========= ========= =========
YEAR ENDED DECEMBER 31, 2000
Acquisition costs $ - $ - $ 170 $ 170
Development costs 47,604 - - 47,604
Exploration costs 94 84 2,470 2,648
--------- --------- --------- ---------
$ 47,698 $ 84 $ 2,640 $ 50,422
========= ========= ========= =========
| United States | ||||||||||||||||
| Venezuela | China | and Other | Total | |||||||||||||
Year Ended December 31, 2003 | ||||||||||||||||
| Development costs | $ | 58,079 | $ | — | $ | 2 | $ | 58,081 | ||||||||
| Exploration costs | 11 | 39 | 133 | 183 | ||||||||||||
| $ | 58,090 | $ | 39 | $ | 135 | $ | 58,264 | |||||||||
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 | ||||||||||||||||
| Acquisition costs | $ | $ | $ | $ | ||||||||||||
| Development costs | 35,194 | 77 | 28 | 35,299 | ||||||||||||
| Exploration costs | 7,694 | — | 909 | 8,603 | ||||||||||||
| $ | 42,888 | $ | 77 | $ | 937 | $ | 43,902 | |||||||||
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS)Capitalized costs related to oil and natural gas producing activities (in thousands):
UNITED STATES
VENEZUELA CHINA AND OTHER TOTAL
--------- --------- ------------- ---------
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 $ 469,218 $ 12,892 $ 19,813 $ 501,923
Costs excluded from amortization - 16,248 560 16,808
Oilfield inventories 15,219 - - 15,219
Less accumulated depletion and impairment (361,313) (12,892) (19,544) (393,749)
--------- --------- --------- ---------
$ 123,124 $ 16,248 $ 829 $ 140,201
========= ========= ========= =========
DECEMBER 31, 2000
Proved property costs $ 426,330 $ 12,879 $ 19,362 $ 458,571
Costs excluded from amortization - 16,183 451 16,634
Oilfield inventories 15,343 - - 15,343
Less accumulated depletion and impairment (339,542) (12,879) (19,090) (371,511)
--------- --------- --------- ---------
$ 102,131 $ 16,183 $ 723 $ 119,037
========= ========= ========= =========
S-26
| United States | ||||||||||||||||
| Venezuela | China | and Other | Total | |||||||||||||
December 31, 2003 | ||||||||||||||||
| Proved property costs | $ | 569,055 | $ | 13,401 | $ | — | $ | 582,456 | ||||||||
| Costs excluded from amortization | — | 2,900 | — | 2,900 | ||||||||||||
| Oilfield inventories | 8,266 | — | — | 8,266 | ||||||||||||
| Less accumulated depletion and impairment | (398,206 | ) | (13,401 | ) | — | (411,607 | ) | |||||||||
| $ | 179,115 | $ | 2,900 | $ | — | $ | 182,015 | |||||||||
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 | $ | 469,218 | $ | 12,892 | $ | 19,813 | $ | 501,923 | ||||||||
| Costs excluded from amortization | — | 16,248 | 560 | 16,808 | ||||||||||||
| Oilfield inventories | 15,219 | — | — | 15,219 | ||||||||||||
| Less accumulated depletion and impairment | (361,313 | ) | (12,892 | ) | (19,544 | ) | (393,749 | ) | ||||||||
| $ | 123,124 | $ | 16,248 | $ | 829 | $ | 140,201 | |||||||||
S-25
TABLE III - RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES
(IN THOUSANDS)Results of operations for oil and natural gas producing activities (in thousands):
UNITED STATES
VENEZUELA CHINA AND OTHER TOTAL
--------- --------- ------------- ---------
YEAR ENDED DECEMBER 31, 2002
Oil sales $ 126,731 $ -- $ -- $ 126,731
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income 31,608 2,493 -- 34,101
Write-down of oil and gas properties
and impairments -- 13,371 1,166 14,537
Depletion 24,941 -- -- 24,941
Income tax expense 4,715 3 -- 4,718
--------- --------- --------- ---------
Total expenses 61,264 15,867 1,166 78,297
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities $ 65,467 $ (15,867) $ (1,166) $ 48,434
========= ========= ========= =========
YEAR ENDED DECEMBER 31, 2001
Oil sales $ 122,386 $ -- $ -- $ 122,386
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income 42,212 -- 722 42,934
Write-down of oil and gas properties
and impairments - 13 455 468
Depletion 22,119 -- -- 22,119
Income tax expense 11,156 -- 13 11,169
--------- --------- --------- ---------
Total expenses 75,487 13 1,190 76,690
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities $ 46,899 $ (13) $ (1,190) $ 45,696
========= ========= ========= =========
YEAR ENDED DECEMBER 31, 2000
Oil and natural gas sales $ 139,890 $ -- $ 394 $ 140,284
Expenses:
Operating, selling and distribution
expenses and taxes other than
on income 46,879 -- 731 47,610
Write-down of oil and gas properties
and impairments -- 8 1,338 1,346
Depletion 15,331 -- 45 15,376
Income tax expense 20,398 -- 12 20,410
--------- --------- --------- ---------
Total expenses 82,608 8 2,126 84,742
--------- --------- --------- ---------
Results of operations from oil and
natural gas producing activities $ 57,282 $ (8) $ (1,732) $ 55,542
========= ========= ========= =========
| United States | ||||||||||||||||
| Venezuela | China | and Other | Total | |||||||||||||
Year ended December 31, 2003 | ||||||||||||||||
| Oil sales | $ | 106,095 | $ | — | $ | — | $ | 106,095 | ||||||||
| Expenses: | ||||||||||||||||
| Operating, selling and distribution expenses and taxes other than on income | 31,445 | — | 76 | 31,521 | ||||||||||||
| Write-down of oil and gas properties and impairments | — | 23 | 142 | 165 | ||||||||||||
| Depletion | 19,599 | — | — | 19,599 | ||||||||||||
| Income tax expense | 12,158 | — | 1,187 | 13,345 | ||||||||||||
| Total expenses | 63,202 | 23 | 1,405 | 64,630 | ||||||||||||
| Results of operations from oil and natural gas producing activities | $ | 42,893 | $ | (23 | ) | $ | (1,405 | ) | $ | 41,465 | ||||||
Year ended December 31, 2002 | ||||||||||||||||
| Oil sales | $ | 126,731 | $ | — | $ | — | $ | 126,731 | ||||||||
| Expenses: | ||||||||||||||||
| Operating, selling and distribution expenses and taxes other than on income | 31,608 | 2,493 | — | 34,101 | ||||||||||||
| Write-down of oil and gas properties and impairments | — | 13,371 | 1,166 | 14,537 | ||||||||||||
| Depletion | 24,941 | — | — | 24,941 | ||||||||||||
| Income tax expense | 4,715 | 3 | — | 4,718 | ||||||||||||
| Total expenses | 61,264 | 15,867 | 1,166 | 78,297 | ||||||||||||
| Results of operations from oil and natural gas producing activities | $ | 65,467 | $ | (15,867 | ) | (1,166 | ) | 48,434 | ||||||||
Year ended December 31, 2001 | ||||||||||||||||
| Oil and natural gas sales | $ | 122,386 | $ | — | $ | — | $ | 122,386 | ||||||||
| Expenses: | ||||||||||||||||
| Operating, selling and distribution expenses and taxes other than on income | 42,212 | — | 722 | 42,934 | ||||||||||||
| Write-down of oil and gas properties and impairments | — | 13 | 455 | 468 | ||||||||||||
| Depletion | 22,119 | — | — | 22,119 | ||||||||||||
| Income tax expense | 11,156 | — | 13 | 11,169 | ||||||||||||
| Total expenses | 75,487 | 13 | 1,190 | 76,690 | ||||||||||||
| Results of operations from oil and natural gas producing activities | $ | 46,899 | $ | (13 | ) | $ | (1,190 | ) | $ | 45,696 | ||||||
TABLE IV - QUANTITIES OF OIL AND NATURAL GAS RESERVESQuantities 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 requiresBenton-Vinccler has requested that the reserve presentation tooperating service agreement period 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 significantlyextended 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 structuretime sales 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 measuredhalted 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 fornational civil work stoppage 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.force majeure clause.
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.
TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------
PROVED RESERVES-CRUDE OIL, CONDENSATE,
AND NATURAL GAS LIQUIDS (MBbls)
YEAR ENDED 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 15,821 32,614 48,435
Revisions of previous estimates 5,327 (5,594) (267)
Extensions, discoveries and improved recovery -- 4,411 4,411
Production (183) (1,763) (1,946)
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves at end of the year 20,965 29,668 50,633
========= ========= =========
YEAR ENDED SEPTEMBER 30, 2000
Proved reserves beginning of the year 3,715 36,414 40,129
Revisions of previous estimates 4,093 (6,904) (2,811)
Extensions, discoveries and improved recovery 8,062 4,548 12,610
Production (49) (1,444) (1,493)
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves at end of the year 15,821 32,614 48,435
========= ========= =========
PROVED DEVELOPED RESERVES AT:
September 30, 2002 -- 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 SEPTEMBER 30, 2002
Proved reserves beginning of the year 208,010 -- 208,010
Revisions of previous estimates -- -- --
Extensions, discoveries and improved recovery -- -- --
Production -- -- --
Sales of reserves in place (208,010) -- (208,010)
--------- --------- ---------
Proved reserves end of the year -- -- --
========= ========= =========
YEAR ENDED SEPTEMBER 30, 2001
Proved reserves beginning of the year 152,496 -- 152,496
Revisions of previous estimates 55,514 -- 55,514
Extensions, discoveries and improved recovery -- -- --
Production -- -- --
Sales of reserves in place -- -- --
--------- --------- ---------
Proved reserves end of the year 208,010 -- 208,010
========= ========= =========
YEAR ENDED SEPTEMBER 30, 2000
Proved reserves beginning of the year -- -- --
Revisions of previous estimates -- -- --
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:
September 30, 2002 -- -- --
September 30, 2001 21,292 -- 21,292
September 30, 2000 17,801 -- 17,801
S-35
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.
TOTAL EQUITY
ARCTIC GAS GEOILBENT AFFILIATES
---------- --------- ------------
(amounts in thousands)
SEPTEMBER 30, 2002
Future cash inflow $ -- $ 469,837 $ 469,837
Future production costs -- 203,754) (203,754)
Future development costs -- (40,707) (40,707)
--------- --------- -----------
Future net revenue before income taxes -- 225,376 225,376
10% annual discount for estimated timing of cash flows -- (108,147 (108,147)
--------- --------- -----------
Discounted future net cash flows before income taxes -- 117,229 117,229
Future income taxes, discounted at 10% per annum -- (24,290) (24,290)
--------- --------- -----------
Standardized measure of discounted future net
cash flows $ -- $ 92,939 $ 92,939
========= ========= ===========
SEPTEMBER 30, 2001
Future cash inflow $ 630,340 $ 434,348 $ 1,064,688
Future production costs (373,458) (251,335) (624,793)
Future development costs (49,139) (37,020) (86,159)
--------- --------- -----------
Future net revenue before income taxes 207,743 145,993 353,736
10% annual discount for estimated timing of cash flows (99,343) (64,868) (164,211)
--------- --------- -----------
Discounted future net cash flows before income taxes 108,400 81,125 189,525
Future income taxes, discounted at 10% per annum (26,195) (10,477) (36,672)
--------- --------- -----------
Standardized measure of discounted future net
cash flows $ 82,205 $ 70,648 $ 152,853
========= ========= ===========
SEPTEMBER 30, 2000
Future cash inflow $ 584,346 $ 688,981 $ 1,273,327
Future production costs (395,238) (416,440) (811,678)
Future development costs (36,585) (34,035) (70,620)
--------- --------- -----------
Future net revenue before income taxes 152,523 238,506 391,029
10% annual discount for estimated timing of cash flows (78,006) (98,346) (176,352)
--------- --------- -----------
Discounted future net cash flows before income taxes 74,517 140,160 214,677
Future income taxes, discounted at 10% per annum (17,637) (25,435) (43,072)
--------- --------- -----------
Standardized measure of discounted future net
cash flows $ 56,880 $ 114,725 $ 171,605
========= ========= ===========
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
EQUITY AFFILIATES
-----------------------------------
2002 2001 2000
--------- --------- ---------
(AMOUNTS IN THOUSANDS)
Present Value at October 1 $ 152,853 $ 171,605 $ 175,913
Sales of oil and natural gas, net of related costs (23,644) (19,001) (20,977)
Revisions to estimates of proved reserves
Net changes in prices, development and production costs 76,545 (39,880) (72,740)
Quantities (10,007) 8,881 (19,685)
Sales of reserves in place (82,205) -- --
Extensions, discoveries and improved recovery, net of future costs 2,031 18,767 73,542
Accretion of discount 7,065 21,468 22,359
Net change in income taxes 1,145 6,400 4,604
Development costs incurred 8,999 17,110 8,475
Changes in timing and other (39,843) (32,497) 114
--------- --------- ---------
Present Value at September 30 $ 92,939 $ 152,853 $ 171,605
========= ========= =========
S-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, 2003.
HARVEST NATURAL RESOURCES, INC.
(Registrant)
Date: March 28, 2003 By: /s/Peter J. Hill
--------------------------------
Peter J. Hill
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed by the following persons on the 28th day of March,
2003, on behalf of the Registrant in the capacities indicated:
Signature Title
- --------- -----
/s/ Peter J. Hill Director, President and Chief Executive
- --------------------------------------------------- Officer
Peter J. Hill
/s/ Steven W. Tholen Senior Vice President, Chief Financial
- --------------------------------------------------- Officer and Treasurer
Steven W. Tholen (Principal Financial Officer)
/s/ Kurt A. Nelson Vice President-Controller
- --------------------------------------------------- (Principal Accounting Officer)
Kurt A. Nelson
/s/ Stephen D. Chesebro' Chairman of the Board and Director
- ---------------------------------------------------
Stephen D. Chesebro'
/s/ John U. Clarke Director
- ---------------------------------------------------
John U. Clarke
/s/ H.H. Hardee Director
- --------------------------------------------------
H.H. Hardee
/s/ Patrick M. Murray Director
- ---------------------------------------------------
Patrick M. Murray
S-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
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(in thousands)
ADDITIONS
-------------------------------
BALANCE AT CHARGED TO DEDUCTIONS BALANCE AT
BEGINNING OF CHARGED TO OTHER FROM END OF
YEAR INCOME ACCOUNTS RESERVES YEAR
------------- ------------- ------------- ------------- --------------
AT DECEMBER 31, 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 $ 6,518 $ 330 $ - $ 336 $ 6,512
Deferred tax valuation allowance 54,207 14,352 (11,008) 37,851 19,700
Investment at cost 1,350 - - - 1,350
AT DECEMBER 31, 2000
Amounts deducted from applicable assets
Accounts receivable $ 6,187 $ 331 - - $ 6,518
Deferred tax valuation allowance 51,913 2,446 - 152 54,207
Investment at cost 1,350 - - - 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 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 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 CommissionSEC 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 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.
S-26
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, 2003, 2002 and 2001 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.
| Minority | ||||||||||||
| Interest in | ||||||||||||
| Venezuela | Venezuela | Net Total | ||||||||||
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) | ||||||||||||
Year ended December 31, 2003 | ||||||||||||
| Proved Reserves beginning of the year | 95,168 | (19,033 | ) | 76,135 | ||||||||
| Revisions of previous estimates | (521 | ) | 104 | (417 | ) | |||||||
| Extensions, discoveries and improved recovery | 572 | (114 | ) | 458 | ||||||||
| Production | (7,347 | ) | 1,469 | (5,878 | ) | |||||||
| Sales of reserves in place | — | — | — | |||||||||
| Proved Reserves at end of the year | 87,872 | (17,574 | ) | 70,298 | ||||||||
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 at beginning of the year | 123,039 | (24,608 | ) | 98,431 | ||||||||
| Revisions of previous estimates | (8,747 | ) | 1,749 | (6,998 | ) | |||||||
| Purchases of reserves in place | — | — | — | |||||||||
| 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 | |||||||||||
S-27
| Minority | ||||||||||||
| Interest in | ||||||||||||
| Venezuela | Venezuela | Net Total | ||||||||||
Proved Developed Reserves at: | ||||||||||||
| December 31, 2003 | 45,860 | (9,172 | ) | 36,688 | ||||||||
| December 31, 2002 | 53,833 | (10,767 | ) | 43,066 | ||||||||
| December 31, 2001 | 51,465 | (10,293 | ) | 41,172 | ||||||||
| January 1, 2001 | 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, 2003 | ||||||||||||
| Proved Reserves beginning of the year | 198,000 | (39,600 | ) | 158,400 | ||||||||
| Revisions of previous estimates | 160 | (32 | ) | 128 | ||||||||
| Extensions, discoveries and improved recovery | — | — | — | |||||||||
| Production | (2,660 | ) | 532 | (2,128 | ) | |||||||
| Proved Reserves end of the year | 195,500 | (39,100 | ) | 156,400 | ||||||||
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, 2003 | 106,147 | (21,229 | ) | 84,918 | ||||||||
| December 31, 2002 | 105,000 | (21,000 | ) | 84,000 | ||||||||
| Russia – Arctic Gas 2001 (39%) | 21,292 | |||||||||||
| Russia – Arctic Gas 2000 (29%) | 17,801 | |||||||||||
| 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 in Venezuela in each of the years. In addition to these reserves is our 34 percent interest in Geoilbent at December 31, 2002 and our Arctic Gas interest of 39% at December 31, 2001. This combined with our Venezuela crude oil and natural gas reserves represent our net interest in all reserves as of December 31, 2003. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.
S-28
| Minority | ||||||||||||
| Interest in | ||||||||||||
| Venezuela | Venezuela | Net Total | ||||||||||
| (amounts in thousands) | ||||||||||||
December 31, 2003 | ||||||||||||
| Future cash inflow | $ | 1,513,525 | $ | (302,705 | ) | $ | 1,210,820 | |||||
| Future production costs | (382,577 | ) | 76,515 | (306,062 | ) | |||||||
| Future development costs | (130,160 | ) | 26,032 | (104,128 | ) | |||||||
| Future net revenue before income taxes | 1,000,788 | (200,158 | ) | 800,630 | ||||||||
| 10% annual discount for estimated timing of cash flows | (319,152 | ) | 63,830 | (255,322 | ) | |||||||
| Discounted future net cash flows before income taxes | 681,636 | (136,328 | ) | 545,308 | ||||||||
| Future income taxes, discounted at 10% per annum | (223,172 | ) | 44,634 | (178,538 | ) | |||||||
| Standardized measure of discounted future net cash flows | $ | 458,464 | $ | (91,694 | ) | $ | 366,770 | |||||
December 31, 2002 | ||||||||||||
| Future cash flows | $ | 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 | ||||||||||
December 31, 2001 | ||||||||||||
| Future cash inflow | $ | 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 | ||||||||||
| TABLE VI — | Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves |
| Net Venezuela | ||||||||||||
| 2003 | 2002 | 2001 | ||||||||||
| (amounts in thousands) | ||||||||||||
| Present Value at January 1 | $ | 317,799 | $ | 163,328 | $ | 284,549 | ||||||
| Sales of oil and natural gas, net of related costs | (59,720 | ) | (76,098 | ) | (64,139 | ) | ||||||
| Revisions to estimates of Proved Reserves | ||||||||||||
| Net changes in prices, development and production costs | 76,037 | 310,043 | (141,429 | ) | ||||||||
| Quantities | (1,584 | ) | 611 | (26,198 | ) | |||||||
| Extensions, discoveries and improved recovery, net of future costs | 4,971 | 89,670 | — | |||||||||
| Accretion of discount | 48,128 | 17,621 | 36,846 | |||||||||
| Net change in income taxes | (15,053 | ) | (150,603 | ) | 71,033 | |||||||
| Development costs incurred | 46,463 | 40,532 | 23,768 | |||||||||
| Changes in timing and other | (50,271 | ) | (77,305 | ) | (21,102 | ) | ||||||
| Present Value at December 31 | $ | 366,770 | $ | 317,799 | $ | 163,328 | ||||||
S-29
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 until sold September 25, 2003) and Arctic Gas (39 percent ownership not subject to certain sale and transfer restrictions at December 31, 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 and 2001.
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 25, 2003 | ||||||||||||
| Development costs | $ | — | $ | 3,474 | $ | 3,474 | ||||||
| Exploration costs | — | 1,034 | 1,034 | |||||||||
| $ | — | $ | 4,508 | $ | 4,508 | |||||||
Year Ended September 30, 2002 | ||||||||||||
| Development costs | $ | — | $ | 8,599 | $ | 8,599 | ||||||
| Exploration costs | 16,156 | 498 | 16,654 | |||||||||
| $ | 16,156 | $ | 9,097 | $ | 25,253 | |||||||
Year Ended September 30, 2001 | ||||||||||||
| Development costs | $ | — | $ | 11,483 | $ | 11,483 | ||||||
| Exploration costs | 8,136 | 2,074 | 10,210 | |||||||||
| $ | 8,136 | $ | 13,557 | $ | 21,693 | |||||||
TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):
| Total Equity | ||||||||||||
| Arctic Gas | Geoilbent | Affiliates | ||||||||||
September 25, 2003 | ||||||||||||
| Proved property costs | $ | — | $ | 102,753 | $ | 102,753 | ||||||
| Oilfield inventories | — | 2,530 | 2,530 | |||||||||
| Less accumulated depletion and impairment | — | (72,333 | ) | (72,333 | ) | |||||||
| $ | — | $ | 32,950 | $ | 32,950 | |||||||
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 | |||||||
S-30
TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
| Total Equity | ||||||||||||
| Arctic Gas | Geoilbent | Affiliates | ||||||||||
Year ended September 25, 2003 | ||||||||||||
| Oil sales | $ | — | $ | 27,876 | $ | 27,876 | ||||||
| Expenses: | ||||||||||||
| Operating, selling and distribution expenses and taxes other than on income | — | 16,088 | 16,088 | |||||||||
| Depletion | — | 6,215 | 6,215 | |||||||||
| Write-down of oil and gas properties | — | 32,300 | 32,300 | |||||||||
| Income tax expense | — | 2,073 | 2,073 | |||||||||
| Total expenses | — | 56,676 | 56,676 | |||||||||
| Results of operations from oil and natural gas producing activities | $ | — | $ | (28,800 | ) | $ | (28,800 | ) | ||||
Year ended September 30, 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 September 30, 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 | ||||||
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 had licenses to develop the North Gubkinskoye and South Tarasovskoye fields in western Siberia. Our 34 percent equity investment in Geoilbent was sold September 25, 2003. Arctic Gas had licenses to develop the Samburg and Yevo-Yakhinskiy fields in western Siberia. Arctic Gas was sold on April 12, 2002.
The SEC 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 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.
S-31
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.
| Total Equity | ||||||||||||
| Arctic Gas | Geoilbent | Affiliates | ||||||||||
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) | ||||||||||||
Year ended September 30, 2003 | ||||||||||||
| Proved reserves beginning of the year | — | 25,356 | 25,356 | |||||||||
| Revisions of previous estimates | — | 537 | 537 | |||||||||
| Extensions, discoveries and improved recovery | — | 962 | 962 | |||||||||
| Production | — | (1,942 | ) | (1,942 | ) | |||||||
| Sales of reserves in place | — | (24,913 | ) | (24,913 | ) | |||||||
| Proved reserves at end of the year | — | — | — | |||||||||
Year ended 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 | 15,821 | 32,614 | 48,435 | |||||||||
| Revisions of previous estimates | 5,327 | (5,594 | ) | (267 | ) | |||||||
| Extensions, discoveries and improved recovery | — | 4,411 | 4,411 | |||||||||
| Production | (183 | ) | (1,763 | ) | (1,946 | ) | ||||||
| Sales of reserves in place | — | — | — | |||||||||
| Proved Reserves at end of the year | 20,965 | 29,668 | 50,633 | |||||||||
Proved Developed Reserves at: | ||||||||||||
| September 30, 2003 | — | — | — | |||||||||
| September 30, 2002 | — | 13,200 | 13,200 | |||||||||
| September 30, 2001 | 2,483 | 15,658 | 18,141 | |||||||||
| October 1, 2000 | 2,325 | 14,913 | 17,238 | |||||||||
Proved Reserves-natural gas (MMcf) | ||||||||||||
Year ended September 30, 2002 | ||||||||||||
| Proved Reserves beginning of the year | 208,010 | — | 208,010 | |||||||||
| Revisions of previous estimates | — | — | — | |||||||||
| Extensions, discoveries and improved recovery | — | — | — | |||||||||
| Production | — | — | — | |||||||||
| Sales of reserves in place | (208,010 | ) | — | (208,010 | ) | |||||||
| Proved Reserves end of the year | — | — | — | |||||||||
S-32
| Total Equity | ||||||||||||
| Arctic Gas | Geoilbent | Affiliates | ||||||||||
Year ended September 30, 2001 | ||||||||||||
| Proved Reserves beginning of the year | 152,496 | — | 152,496 | |||||||||
| Revisions of previous estimates | 55,514 | — | 55,514 | |||||||||
| Extensions, discoveries and improved recovery | — | — | — | |||||||||
| Production | — | — | — | |||||||||
| Sales of reserves in place | — | — | — | |||||||||
| Proved Reserves end of the year | 208,010 | — | 208,010 | |||||||||
Proved Developed Reserves at: | ||||||||||||
| September 30, 2002 | — | — | — | |||||||||
| September 30, 2001 | 21,292 | — | 21,292 | |||||||||
| October 1, 2000 | 17,801 | — | 17,801 | |||||||||
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.
| Total Equity | ||||||||||||
| Arctic Gas | Geoilbent | Affiliates | ||||||||||
| (amounts in thousands) | ||||||||||||
September 30, 2003 | ||||||||||||
| Future cash inflow | $ | — | $ | 481,557 | $ | 481,557 | ||||||
| Future production costs | — | (229,982 | ) | (229,982 | ) | |||||||
| Future development costs | — | (36,666 | ) | (36,666 | ) | |||||||
| Future net revenue before income taxes | — | 214,909 | 214,909 | |||||||||
| 10% annual discount for estimated timing of cash flows | — | (99,948 | ) | (99,948 | ) | |||||||
| Discounted future net cash flows before income taxes | — | 114,961 | 114,961 | |||||||||
| Future income taxes, discounted at 10% per annum | — | (23,163 | ) | (23,163 | ) | |||||||
| Standardized measure of discounted future net cash flows | $ | — | $ | 91,798 | $ | 91,798 | ||||||
September 30, 2002 | ||||||||||||
| Future cash inflow | $ | — | $ | 469,837 | $ | 469,837 | ||||||
| Future production costs | — | (203,754 | ) | (203,754 | ) | |||||||
| Future development costs | — | (40,707 | ) | (40,707 | ) | |||||||
| Future net revenue before income taxes | — | 225,376 | 225,376 | |||||||||
| 10% annual discount for estimated timing of cash flows | — | (108,147 | ) | (108,147 | ) | |||||||
| Discounted future net cash flows before income taxes | — | 117,229 | 117,229 | |||||||||
| Future income taxes, discounted at 10% per annum | — | (24,290 | ) | (24,290 | ) | |||||||
| Standardized measure of discounted future net cash flows | $ | — | $ | 92,939 | $ | 92,939 | ||||||
September 30, 2001 | ||||||||||||
| Future cash inflow | $ | 630,340 | $ | 434,348 | $ | 1,064,688 | ||||||
| Future production costs | (373,458 | ) | (251,335 | ) | (624,793 | ) | ||||||
| Future development costs | (49,139 | ) | (37,020 | ) | (86,159 | ) | ||||||
| Future net revenue before income taxes | 207,743 | 145,993 | 353,736 | |||||||||
| 10% annual discount for estimated timing of cash flows | (99,343 | ) | (64,868 | ) | (164,211 | ) | ||||||
| Discounted future net cash flows before income taxes | 108,400 | 81,125 | 189,525 | |||||||||
| Future income taxes, discounted at 10% per annum | (26,195 | ) | (10,477 | ) | (36,672 | ) | ||||||
| Standardized measure of discounted future net cash flows | $ | 82,205 | $ | 70,648 | $ | 152,853 | ||||||
S-33
TABLE VI - Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves | ||
| Equity Affiliates | |||||||||||||||||
| 2003 | 2002 | 2001 | |||||||||||||||
| (amounts in thousands) | |||||||||||||||||
| Present Value at October 1 | $ | 92,939 | $ | 152,853 | $ | 171,605 | |||||||||||
| Sales of oil and natural gas, net of related costs | (20,410 | ) | (23,644 | ) | (19,001 | ) | |||||||||||
| Revisions to estimates of Proved Reserves | |||||||||||||||||
| Net changes in prices, development and production costs | (5,522 | ) | 76,545 | (39,880 | ) | ||||||||||||
| Quantities | 3,178 | (10,007 | ) | 8,881 | |||||||||||||
| Sales of reserves in place | (91,797 | ) | (82,205 | ) | — | ||||||||||||
| Extensions, discoveries and improved recovery, net of future costs | 1,245 | 2,031 | 18,767 | ||||||||||||||
| Accretion of discount | 11,723 | 7,065 | 21,468 | ||||||||||||||
| Net change in income taxes | 1,127 | 1,145 | 6,400 | ||||||||||||||
| Development costs incurred | 4,507 | 8,999 | 17,110 | ||||||||||||||
| Changes in timing and other | 3,010 | (39,843 | ) | (32,497 | ) | ||||||||||||
| Present Value at September 30 | $ | — | $ | 92,939 | $ | 152,853 | |||||||||||
S-34
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.
| HARVEST NATURAL RESOURCES, INC. | ||||
| (Registrant) | ||||
| Date: March 9, 2004 | By: | /s/ Peter J. Hill | ||
| Peter J. Hill | ||||
| Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 9th day of March, 2004, on behalf of the registrant and in the capacities indicated:
| Signature | Title | |
| /s/Peter J. Hill | Director, President and Chief Executive | |
| Officer | ||
| Peter J. Hill | ||
| /s/ Steven W. Tholen | Senior Vice President, Chief Financial | |
| Officer and Treasurer | ||
| Steven W. Tholen (Principal Financial Officer) | ||
| /s/ Kurt A. Nelson | Vice President-Controller | |
| Kurt A. Nelson | ||
| (Principal Accounting Officer) | ||
| /s/ Stephen D. Chesebro’ | Chairman of the Board and Director | |
| Stephen D. Chesebro’ | ||
| /s/ John U. Clarke | Director | |
| John U. Clarke | ||
| /s/ Byron A. Dunn | Director | |
| Byron A. Dunn | ||
| /s/ H. H. Hardee | Director | |
| H.H. Hardee | ||
| /s/ Patrick M. Murray | Director | |
| Patrick M. Murray |
S-35
SCHEDULE II
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(in thousands)
| Additions | ||||||||||||||||||||
| Balance at | Charged to | Deductions | Balance at | |||||||||||||||||
| Beginning | Charged to | Other | From | End of | ||||||||||||||||
| of Year | Income | Accounts | Reserves | Year | ||||||||||||||||
At December 31, 2003 | ||||||||||||||||||||
| Amounts deducted from applicable assets | ||||||||||||||||||||
| Accounts receivable | $ | 3,525 | $ | 205 | $ | — | $ | 375 | $ | 3,355 | ||||||||||
| Deferred tax valuation allowance | 39,146 | 9,219 | — | — | 48,365 | |||||||||||||||
| Investment at cost | 1,350 | — | — | — | 1,350 | |||||||||||||||
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 | $ | 6,518 | $ | 330 | $ | — | $ | 336 | $ | 6,512 | ||||||||||
| Deferred tax valuation allowance | 54,207 | 14,352 | (11,008 | ) | 37,851 | 19,700 | ||||||||||||||
| Investment at cost | 1,350 | — | — | — | 1,350 | |||||||||||||||
S-36
SCHEDULE III
Financial Statements and Notes
for LLC Geoilbent
LLC Geoilbent
Financial Statements
30 September 2003
REPORT OF INDEPENDENT AUDITORS
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 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended 30 September 2003, 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 10 to the financial statements, the Company has a long-term debt facility for which it is in violation of 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$35,772,000 as at 30 September 2003 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 Audit
Moscow, Russian Federation
2 March 2003
LLC GEOILBENT
BALANCE SHEETS
(expressed in thousand of US Dollars)
| As at | As at | |||||||||||
| Notes | 30 September 2003 | 30 September 2002 | ||||||||||
Assets | ||||||||||||
| Cash and cash equivalents | 680 | 2,001 | ||||||||||
| Restricted cash | 10 | 1,217 | 1,469 | |||||||||
| Accounts receivable and advances to suppliers | 7 | 7,161 | 6,308 | |||||||||
| Inventories | 8 | 8,018 | 7,201 | |||||||||
| Deferred income tax, current | 14 | 966 | 1,806 | |||||||||
Total current assets | 18,042 | 18,785 | ||||||||||
| Oil and gas producing properties, full cost method | 9 | 89,469 | 185,989 | |||||||||
| Deferred income tax, non-current | 14 | — | 696 | |||||||||
| Other long term assets | — | 130 | ||||||||||
Total assets | 107,511 | 205,600 | ||||||||||
Liabilities and Stockholders’ Equity | ||||||||||||
| Current portion of long-term debt | 10 | 37,500 | 22,550 | |||||||||
| Accounts payable | 6,559 | 15,244 | ||||||||||
| Trade advances | 993 | 3,000 | ||||||||||
| Taxes payable | 11 | 7,858 | 12,354 | |||||||||
| Other payables and accrued liabilities | 904 | 903 | ||||||||||
Total current liabilities | 53,814 | 54,051 | ||||||||||
| Long-term debt | 10 | — | 7,500 | |||||||||
| Asset retirement obligation | 3 | 734 | — | |||||||||
Total liabilities | 54,548 | 61,551 | ||||||||||
Commitments and contingent liabilities | 16 | — | — | |||||||||
| Contributed capital | 12 | 82,518 | 82,518 | |||||||||
| Retained earnings (accumulated deficit) | (23,353 | ) | 61,531 | |||||||||
| Accumulated other comprehensive loss | (6,202 | ) | — | |||||||||
Total stockholders’ equity | 52,963 | 144,049 | ||||||||||
Total liabilities and stockholders’ equity | 107,511 | 205,600 | ||||||||||
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
STATEMENTS OF INCOME
(expressed in thousand of US Dollars)
| Year ended | Year ended | Year ended | ||||||||||||||
| Notes | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||||||
Total sales and other operating revenues | 13 | 82,307 | 91,598 | 101,159 | ||||||||||||
Costs and other deductions | ||||||||||||||||
| Operating expenses | 15,801 | 15,360 | 11,415 | |||||||||||||
| Selling and distribution expenses | 5,893 | 6,696 | 9,876 | |||||||||||||
| General and administrative expenses | 9,456 | 8,335 | 5,650 | |||||||||||||
| Depletion and amortization expense | 18,278 | 27,168 | 14,918 | |||||||||||||
| Impairment of property, plant and equipment | 9 | 95,000 | — | — | ||||||||||||
| Taxes other than income tax | 14 | 25,625 | 27,657 | 26,011 | ||||||||||||
Total costs and other deductions | 170,053 | 85,216 | 67,870 | |||||||||||||
Other income and expense | ||||||||||||||||
| Exchange gain, net | (1,566 | ) | (2,053 | ) | (781 | ) | ||||||||||
| Interest expense, net | 1,992 | 4,629 | 7,547 | |||||||||||||
| Other non-operating income, net | (481 | ) | (381 | ) | (648 | ) | ||||||||||
Total other expense (income) | (55 | ) | 2,195 | 6,118 | ||||||||||||
Income (loss) before income tax | (87,691 | ) | 4,187 | 27,171 | ||||||||||||
Income tax expense | 14 | |||||||||||||||
| Current income tax expense | 3,542 | 2,804 | 6,751 | |||||||||||||
| Deferred income tax benefit | (6,659 | ) | (2,502 | ) | — | |||||||||||
Total income tax expense (benefit) | (3,117 | ) | 302 | 6,751 | ||||||||||||
Income (loss) before cumulative effect of change in accounting principle, net of tax | (84,574 | ) | 3,885 | 20,420 | ||||||||||||
| Cumulative effect of change in accounting principle, net of tax | 3 | (310 | ) | — | — | |||||||||||
Net income (loss) | (84,884 | ) | 3,885 | 20,420 | ||||||||||||
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
STATEMENTS OF CASHFLOWS
(expressed in thousand of US Dollars)
| Year ended | Year ended | Year ended | ||||||||||
| 30 September 2003 | 30 September 2002 | 30 September 2001 | ||||||||||
Cash flows from operating activities | ||||||||||||
| Net income (loss) | (84,884 | ) | 3,885 | 20,420 | ||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
| Depletion and amortization expense | 18,278 | 27,168 | 14,918 | |||||||||
| Impairment of oil and gas properties | 95,000 | — | — | |||||||||
| Amortization of financing costs | 130 | 520 | 520 | |||||||||
| Exchange gain | (1,566 | ) | (2,053 | ) | (781 | ) | ||||||
| Deferred tax benefit | (6,659 | ) | (2,502 | ) | — | |||||||
| Decrease/(increase) in accounts receivable and advances to suppliers | (631 | ) | 403 | 85 | ||||||||
| Decrease/(increase) in inventories | (544 | ) | 6,362 | (4,700 | ) | |||||||
| Increase/(decrease) in accounts payable | (9,030 | ) | (3,407 | ) | 11,902 | |||||||
| Increase/(decrease) in trade advances | (2,070 | ) | (5,747 | ) | 3,785 | |||||||
| Increase/(decrease) in taxes payable | (4,822 | ) | 5,436 | 4,780 | ||||||||
| Decrease in other payables and accrued liabilities | (28 | ) | (1,378 | ) | (2,386 | ) | ||||||
Cash provided by operating activities | 3,174 | 28,687 | 48,543 | |||||||||
Cash flow from investing activities | ||||||||||||
| Capital expenditures | (13,257 | ) | (26,755 | ) | (39,874 | ) | ||||||
| Proceeds on disposal of oil and gas producing properties | 1,023 | 286 | 191 | |||||||||
| Disposal/(purchase) of investments | — | 367 | (129 | ) | ||||||||
Net cash used in investing activities | (12,234 | ) | (26,102 | ) | (39,812 | ) | ||||||
Cash flows from financing activities | ||||||||||||
| Payment of short-term borrowings from founders | — | — | (717 | ) | ||||||||
| Payment of short-terms borrowings | — | (3,000 | ) | (3,845 | ) | |||||||
| Proceeds from short-term borrowings | — | — | 6,446 | |||||||||
| Proceeds from long-term borrowings from founders | — | 7,500 | — | |||||||||
| Payments of long-term borrowings | (550 | ) | (18,200 | ) | (10,455 | ) | ||||||
| Proceeds from long-term borrowings | 8,000 | — | — | |||||||||
| Decrease in restricted cash | 252 | 8,738 | 2,153 | |||||||||
Net cash provided by (used in) financing activities | 7,702 | (4,962 | ) | (6,418 | ) | |||||||
| Effect of foreign exchange on cash balances | 37 | (31 | ) | (37 | ) | |||||||
Net decrease in cash and cash equivalents | (1,321 | ) | (2,408 | ) | 2,276 | |||||||
| Cash and cash equivalents, beginning of year | 2,001 | 4,409 | 2,133 | |||||||||
| Cash and cash equivalents, end of year | 680 | 2,001 | 4,409 | |||||||||
Supplemental cash flow information | ||||||||||||
| Interest paid | 1,977 | 4,862 | 7,609 | |||||||||
| Income taxes paid | 2,388 | 2,747 | 6,906 | |||||||||
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(expressed in thousands of US Dollars except as indicated)
| Total | ||||||||||||||||
| Contributed | Retained earnings | Accumulated other | stockholders' | |||||||||||||
| Capital | (accumulated deficit) | comprehensive loss | equity | |||||||||||||
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 | ||||||||||||
| Net loss | — | (84,884 | ) | — | (84,884 | ) | ||||||||||
| Cumulative translation adjustment | — | — | (6,202 | ) | (6,202 | ) | ||||||||||
| Total comprehensive loss | (91,086 | ) | ||||||||||||||
Balance at 30 September 2003 | 82,518 | (23,353 | ) | (6,202 | ) | 52,963 | ||||||||||
The accompanying notes are an integral part of these financial statements.
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 by 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. In September 2003, Harvest sold its interests in the Company to a company affiliated with OAO YUKOS (“YUKOS”).
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 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 net income or stockholders’ equity.
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.
In November 2002, the International Practices Task Force concluded that Russia ceased being a highly inflationary economy as of 1 January 2003. As a result of the Task Force conclusion, the Company applied the guidance contained in Emerging Issues Task Force (“EITF”) No. 92-4 and EITF No. 92-8 as of 1 January 2003, which address changes in accounting when an economy ceases to be considered highly inflationary. As a result of the application of the guidance in EITF No. 92-4 and No. 92-8, as of 1 January 2003, the Company recognised a deferred tax liability of USD 8.1 million for temporary differences related to its property, plant and equipment and a corresponding amount as a cumulative translation adjustment as a separate component in stockholders’ equity.
Effective 1 January 2003, the measurement currency of the Company is the Russian Rouble. The transactions and balances in the accompanying financial statements have been translated into US dollars in accordance with the relevant provisions of Statement of Financial Accounting Standards (“SFAS”) No. 52,Foreign Currency Translation(“SFAS No. 52”). Consequently, assets and liabilities are translated at closing exchange rates. The statements of income and cash flows have been translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates have been included as a component of stockholders equity. The amount of such differences for the period beginning 1 January 2003 through 30 September 2003 was approximately USD 1.9 million. The exchange rates at 30 September 2003, and 30 September 2002, were 30.61 and 31.64, respectively, Russian Roubles to the US dollar.
Prior to 1 January 2003, transactions not already measured in US dollars were remeasured into US dollars in accordance with the relevant provisions of SFAS No. 52 as applied to hyperinflationary economies. Consequently, monetary assets and liabilities were translated at closing exchange rates and non-monetary items were translated at historic exchange rates and adjusted for any impairments. The statements of income and cash flows were translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates were included in the determination of net income and were included in exchange gains/losses in the accompanying statements of income through 31 December 2002.
1
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 2: Basis of Presentation (continued)
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 realise 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. At 30 September 2003, the Company was required to sell 25% of its foreign currency receipts within the Russian Federation to the Central Bank for Russian Roubles. Such amounts are subject to certain deductions depending on debt payments on certain hard currency denominated borrowing agreements.
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 realisable 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 realisable value. Materials and supplies inventories are recorded at the lower of average cost or net realisable 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 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, estimated asset retirement obligations, net of prior accumulated depletion, is depleted using the unit-of-production method based upon actual production and estimates of proved 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. During 2003, the Company’s capitalized costs exceeded the ceiling limit resulting in an impairment of oil and gas properties. See Note 9 for additional information.
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 and gas condensate are recognized when dispatched to customers and title has transferred.
2
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 3: Summary of Significant Accounting Policies (continued)
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.
Change in accounting principle. Effective 1 October 2002, the Company adopted Statement of Financial Accounting Standards No. 143,Accounting for Assets Retirement Obligations(“SFAS No. 143”). SFAS No. 143 requires entities to record the fair value of its asset retirement obligation as a liability in the period in which they are incurred and a corresponding increase in the carrying amount of the related long-lived asset.
SFAS No. 143 differs in several respects from the previous accounting method employed by the Company. Prior to the adoption of SFAS No. 143, the Company included estimated undiscounted asset retirement costs in its calculation for determining depletion expense. Under SFAS 143, the Company recognizes a liability for the fair value of an asset retirement obligation (“ARO”) in the period in which it is incurred, and capitalizes the associated asset retirement cost. In periods subsequent to initial measurement, the Company recognizes period-to-period changes in the liability for an ARO resulting from a) the passage of time and b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The Company’s asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities.
The cumulative effect of this change in accounting principle was a reduction in net income of USD 310 thousand, net of tax, which was recorded in the statement of income for the year ended 30 September 2003. The effect of adoption resulted in increases in property, plant and equipment and long-tem liabilities of USD 303 thousand and USD 613 thousand as of 1 October 2002, respectively.
The following table provides pro forma information as if SFAS No. 143 has been applied in previous periods:
| Year ended | Year ended | Year ended | ||||||||||
| Thousands of US dollars | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||
| Asset retirement obligations as of the beginning of the period | 613 | 483 | 358 | |||||||||
| Liabilities incurred for the period | 25 | 56 | 79 | |||||||||
| Accretion expense | 96 | 75 | 45 | |||||||||
| Asset retirement obligations as of the end of the period | 734 | 613 | 483 | |||||||||
| Net income for the period as reported | 3,885 | 20,420 | ||||||||||
| Pro-forma net income | 3,777 | 20,358 | ||||||||||
Recent accounting standards.FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities(“FIN 46R”), identifies certain off-balance sheet arrangements that meet the definition of a variable interest entity (“VIE”). FIN 46R requires consolidation of VIEs by primary beneficiaries and requires more extensive disclosures. FIN 46R is applicable to any VIE created after 1 February 2003. The Company does not expect the adoption of this interpretation will have any material effect on its financial position or results of operations.
3
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 4: Going Concern
During the years ended 30 September 2003 and 2002 the Company took steps to reduce its working capital deficit. These included the repayment of debt, the receipt of subordinated long-term loans from the Company’s stockholders and the repayment of accounts payable, primarily from additional borrowings from the European Bank for Reconstruction and Development (“EBRD”). However, as at 30 September 2003, and 30 September 2002, the current liabilities of the Company exceeded its current assets by USD 35,772 thousand and USD 35,266 thousand, respectively. Included in current liabilities, as at 30 September 2003 and 30 September 2002, are loans repayable to the EBRD of USD 30,000 thousand and USD 22,000 thousand, respectively. This debt has been reclassified as current because the Company is not in compliance with a loan facility covenant related to the required implementation of a new management information system, required by 1 May 2003. The loan facility also requires the Company to maintain a minimum working capital ratio. The Company was not in compliance with the required working capital ratio as of the interim reporting dates during the year ended 30 September 2003, however, it met the minimum required working capital ratio as of 30 September 2003 (see also Note 10). Under the terms of the loan facility the EBRD may declare the loan to be in default and can accelerate the maturity. There can be no assurance that the EBRD will not demand repayment of the loan.
During the year ended 30 September 2003, a substantial portion of the Company’s cash flow was utilised to pay accounts and taxes payable resulting in a reduction in capital expenditures for the year. In order to maintain or increase proved oil and gas reserves, the Company must make substantial capital expenditures in 2004 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 resolving issues with the EBRD relating to its non compliance with the loan covenants and by reducing certain capital expenditures and funding its 2004 cash requirements with cash flows from existing producing properties and its development drilling program. Management is in the process of implementing the required management information system and expects to have implemented this system during the 2004 reporting year. 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 2003, and 2002, respectively, are Russian Rouble denominated amounts totaling RR 19.7 million (USD 643 thousand) and RR 18.3 million (USD 578 thousand).
Restricted cash consists of deposits with lending institutions to pay interest and principal as discussed in Note 10. As at 30 September 2003, the amount of restricted cash was USD 1,217 thousand (2002: USD 1,469 thousand). These accounts are maintained in US Dollar denominated accounts located outside Russia.
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.
4
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 6: Financial Instruments (continued)
Credit risk. 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 the economic situation in the Russian Federation does not deteriorate (Note 16).
Note 7: Accounts Receivable and Advances to Suppliers
| Thousands of US dollars | 30 September 2003 | 30 September 2002 | ||||||
| Trade accounts receivable | 1,531 | 1,387 | ||||||
| Recoverable value-added tax | 4,227 | 3,515 | ||||||
| Advances to suppliers | 1,286 | 1,193 | ||||||
| Advances to customs | 117 | 137 | ||||||
| Other receivables | — | 76 | ||||||
Total accounts receivable and advances to suppliers | 7,161 | 6,308 | ||||||
Accounts receivables are presented net of an allowance for doubtful accounts of USD 147 thousand and USD 70 thousand at 30 September 2003 and 2002, respectively.
Note 8: Inventories
| Thousands of US Dollars | 30 September 2003 | 30 September 2002 | ||||||
| Materials and supplies | 7,442 | 6,905 | ||||||
| Crude oil | 576 | 296 | ||||||
Total inventories | 8,018 | 7,201 | ||||||
Note 9: Oil and Gas Producing Properties
| Thousands of US dollars | 30 September 2003 | 30 September 2002 | ||||||
| Oil and gas producing properties, cost | 302,214 | 278,459 | ||||||
| Accumulated depletion and impairment | (212,745 | ) | (92,470 | ) | ||||
Oil and gas producing properties, net book value | 89,469 | 185,989 | ||||||
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 9 percent of total proved reserves.
At 31 December 2002 and at 31 March 2003, the Company’s capitalized costs for oil and gas producing properties exceeded its full cost accounting ceiling limitation. The Company’s ceiling limitation decreased primarily because of a decline in the Company’s average realized price it received for its oil at those dates. As a result the Company recorded impairments of its oil and gas producing properties in the aggregate amount of USD 95 million (excluding a deferred income tax benefit of USD 7.6 million); this impairment was recorded as an impairment expense in the statement of income for the year ended 30 September 2003.
5
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 10: Long-term Debt
| Thousands of US dollars | 30 September 2003 | 30 September 2002 | ||||||
| EBRD | 30,000 | 22,000 | ||||||
| IMB | — | 550 | ||||||
| OAO Minley | 5,000 | 5,000 | ||||||
| YUKOS | 2,500 | — | ||||||
| Harvest Natural Resources | — | 2,500 | ||||||
| Less: current portion | (37,500 | ) | (22,550 | ) | ||||
Total long-term debt | — | 7,500 | ||||||
EBRD loan.At 30 September 2003, the outstanding balance of loans with the EBRD totaled USD 30 million. On 23 September 2002, the Company signed an amended loan agreement with the EBRD that increased the maximum amount that could be drawn down under the facility with the EBRD to USD 50 million. Under the loan agreement, the use of loan proceeds is restricted to the repayment of accounts payable and development of oil and gas reserves. This loan facility is to be repaid such that the loan balance may not exceed set amounts at certain dates in the future. The interest rate under the loan agreement is linked to the London interbank offer rate (“LIBOR”) and an agreed upon margin. The Company must hold as restricted cash a) principal and interest to be paid at the next repayment date and b) 30 percent of the total of principal and interest to be paid at the following repayment date.
LIBOR interest rates ranged from 1.12 percent to 1.84 percent in 2003 (2002: 1.84 percent to 3.5 percent, 2001: 3.5 percent to 6.94 percent). The annual weighted average interest rates on these loans varied between 5.09 percent and 5.43 percent for the year ended 30 September 2003 (2002: 8.59 percent and 11.71 percent, 2001: 14.93 percent to 15.17 percent). The loan is collaterized by the Company’s immovable assets and crude oil export contracts.
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. As dicussed in Note 4, as of 31 December 2002, 31 March 2003 and 30 June 2003 the Company was in violation of the minimum working capital ratio covenant. As of 30 September 2003, the minimum working capital ratio as defined in the loan facility exceeds the covenant requirements. Additionally, the Company has not completed its implementation of a management information system as required under the terms of the loan. Due to these loan convenant violations, the Company has classified the EBRD debt as a current liability.
In addition, while in default of EBRD covenants, the Company may not declare or pay any dividend, make any distribution on its charter capital, purchase, or redeem any shares of the charter capital of the Company, nor make any payment of principal or interest on subordinated shareholder loans or make any other payment or distribution to any stockholder or any affiliate of any stockholder.
As part of the sale of Harvest’s interest in the Company to YUKOS, as described in Note 1, YUKOS assumed Harvest’s stockholder loan.
Loans from OAO Minley and YUKOS are subordinated, unsecured and repayable commencing from January 2004. Interest rates are 2 percent for the Minley loan, and LIBOR for the YUKOS loan, to January 2004. Repayment of the subordinated loans are subject to approval from the EBRD. If approval is not received, the terms of the loan agreements are not considered to be violated. After January 2004, the interest rates on the YUKOS loan increases to 8 percent for the remainder of 2004, and 12 percent from 2005 onwards.
6
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 10: Long-term Debt (continued)
While the Company remains in violation of its EBRD loan convenants, further borrowings under the facility are at the sole discretion of the EBRD. The maximum loan facility available under the terms of the EBRD loan and the related aggregate maturities are as follows:
| Maximum loan facility | ||||
| Thousands of US dollars | outstanding | |||
| 30 September 2003 to 27 January 2004 | 50,000 | |||
| 27 January 2004 to 27 July 2004 | 41,667 | |||
| 27 July 2004 to 27 January 2005 | 33,333 | |||
| 27 January 2005 to 27 July 2005 | 25,000 | |||
| 27 July 2005 to 27 January 2006 | 16,667 | |||
| 27 January 2006 to 27 January 2007 | 8,333 | |||
| Thereafter | — | |||
The aggregate maturities of long-term debt outstanding at 30 September 2003 are as follows:
| Thousands of US dollars | ||||
| Year ended 30 September 2004 | 7,500 | |||
| Year ended 30 September 2005 | 5,000 | |||
| Year ended 30 September 2006 | 8,333 | |||
| Year ended 30 September 2007 | 8,333 | |||
| Year ended 30 September 2008 | 8,333 | |||
Note 11: Taxes Payable
| Thousands of US dollars | 30 September 2003 | 30 September 2002 | ||||||
| Value added tax | — | 1,445 | ||||||
| Income tax | 3,777 | 1,176 | ||||||
| Royalty | — | 896 | ||||||
| Mineral restoration tax | — | 152 | ||||||
| Road users tax | — | 642 | ||||||
| Unified production tax | 1,552 | 6,703 | ||||||
| Property taxes | 586 | 1,121 | ||||||
| Penalties and interest | 1,784 | 219 | ||||||
| Other taxes | 159 | — | ||||||
Total taxes payable | 7,858 | 12,354 | ||||||
7
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 12: Contributed Capital
Capital contributions are as follows:
| Thousands of US dollars | 30 September 2003 | 30 September 2002 | ||||||
| OAO Minley | 54,733 | 54,733 | ||||||
| YUKOS | 27,785 | — | ||||||
| Harvest Natural Resources | — | 27,785 | ||||||
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 differ from US GAAP. Russian legislation identifies the basis of distribution as net income. For 2002, the current year statutory net income for the Company as reported in the annual statutory accounting reports was RR 772 million (2001: 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. The Company cannot distribute capital while in default of its EBRD loan facility obligations (Note 10).
Note 13: Revenues
Revenues for the years ended 30 September 2003, 2002 and 2001, consisted of the following:
| Thousand of US dollars | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||
| Crude oil — export (Europe and CIS) | 51,949 | 47,751 | 83,889 | |||||||||
| Crude oil — domestic | 28,599 | 40,778 | 10,900 | |||||||||
| Gas condensate — domestic | 1,176 | — | — | |||||||||
| Refined products — domestic | — | 2,764 | 6,231 | |||||||||
| Other operating revenues | 583 | 305 | 139 | |||||||||
Total sales and other operating revenues | 82,307 | 91,598 | 101,159 | |||||||||
Note 14: 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 2003 | 30 September 2002 | 30 September 2001 | |||||||||
| Income (loss) before income taxes | (87,691 | ) | 4,187 | 27,171 | ||||||||
| Theoretical income tax expense (benefit) at statutory rate (24% in 2002 and 2003; 35% in 2001) | (21,046 | ) | 1,005 | 9,509 | ||||||||
| Increase (reduction) due to: | ||||||||||||
| Change in valuation allowance | 17,192 | 80 | 1,810 | |||||||||
| Non-deductible expenses | 1,860 | 2,894 | 2,693 | |||||||||
| Investment tax credits | (593 | ) | (5,348 | ) | (6,821 | ) | ||||||
| Change in statutory tax rate | — | 595 | (750 | ) | ||||||||
| Tax penalties and interest | 442 | 1,135 | 517 | |||||||||
| Other | (972 | ) | (59 | ) | (207 | ) | ||||||
Total income tax expense (benefit) | (3,117 | ) | 302 | 6,751 | ||||||||
8
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 14: Taxes (continued)
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 2003 and 2002:
| Thousand of US dollars | 30 September 2003 | 30 September 2002 | ||||||
| Inventories | (313 | ) | 93 | |||||
| Accounts receivable | 121 | 258 | ||||||
| Accounts payable and accrued liabilities | 1,205 | 430 | ||||||
| Losses carried forward | 966 | 2,502 | ||||||
| Property, plant and equipment | 4,989 | 4,810 | ||||||
| Total deferred tax assets | 6,968 | 8,093 | ||||||
| Less: Valuation allowance | (6,002 | ) | (5,591 | ) | ||||
Net deferred tax asset | 966 | 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 2003, management of the Company have assessed the recoverability of the Company’s deferred tax assets and believe that it will be able to realise the tax losses carried forward. Accordingly, the Company has provided a valuation allowance as at 30 September 2003 and 2002, of USD 6,002 thousand and USD 5,591 thousand, respectively, against the remaining deferred tax assets.
Principal movements in the valuation allowance for deferred income tax assets (“DTA”) during the year ended 30 September 2003 are as follows:
| Millions of US dollars | ||||
| Valuation allowance, beginning of period | 5.6 | |||
| Increase related to DTA resulting from the December ceiling test writedown | 12.0 | |||
| Net other increase in DTA movements during the December quarter | 1.0 | |||
| Decrease due to application of EITF No. 92-4 and No. 92-8 effective 1 January 2003 | (16.8 | ) | ||
| Increase relating to DTA resulting from the March ceiling test writedown | 3.2 | |||
| Net other increase in DTA movements | 1.0 | |||
Valuation allowance, end of period | 6.0 | |||
As a result of the application of EITF No. 92-4 and No. 92-8, the valuation allowance related to property, plant and equipment was reduced to zero and a deferred tax liability of USD 8.1 million recorded on 1 January 2003 (Note 2), with no effect on income as the adjustment was recorded as part of the currency translation adjustment as of 1 January 2003. A subsequent ceiling test writedown in March resulted in the recognition of an additional deferred tax asset of USD 10.8 million of which USD 7.6 million and USD 3.2 million were credited as a deferred tax benefit and an increase to the DTA valuation allowance, respectively.
Deferred income tax assets are classified as follows:
| Thousands of US dollars | 30 September 2003 | 30 September 2002 | ||||||
| Deferred income tax, current | 966 | 1,806 | ||||||
| Deferred income tax, non-current | — | 696 | ||||||
Total net deferred tax asset | 966 | 2,502 | ||||||
9
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 14: Taxes (continued)
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 2003 | 30 September 2002 | 30 September 2001 | |||||||||
| Export duties | 8,464 | 5,376 | 10,922 | |||||||||
| Excise tax | — | 535 | 1,548 | |||||||||
| Royalty | — | 2,254 | 4,867 | |||||||||
| Mineral restoration tax | 377 | 885 | 4,596 | |||||||||
| Road users tax | 203 | 860 | 1,427 | |||||||||
| Unified production tax | 19,056 | 14,221 | — | |||||||||
| Property taxes | 2,263 | 1,994 | 1,424 | |||||||||
| Taxes recovery | (7,017 | ) | — | — | ||||||||
| Other taxes | 2,279 | 1,532 | 1,227 | |||||||||
Total taxes other than income tax | 25,625 | 27,657 | 26,011 | |||||||||
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. From 1 January 2004 through 31 December 2006, the base rate for the unified natural resources production tax is set at RR 347 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 2007, 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 Tax Regulations of the Russian Federation.
During the year ended 30 September 2003, the Company pursued its claim of overpayment of mineral restoration taxes (MRT) paid during the period from 1999 to 2001 of approximately RR 211 million (USD 7.0 million), plus approximately RR 4 million (USD 0.1 million) in related penalties paid. During the year, the regional courts ruled in favour of the Company and, accordingly, the Company and the tax authorities agreed to offset the amounts awarded against the Company’s unified production taxes payable.
Note 15: Related Party Transactions
As of 30 September 2003 and 2002, 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 2003 | 30 September 2002 | ||||||
Accounts receivable | ||||||||
| Purneftegasgeologia and affiliated entities | 19 | 63 | ||||||
Accounts payable | ||||||||
| Purneftegasgeologia and affiliated entities | 183 | 574 | ||||||
| YUKOS | 2,111 | — | ||||||
| Harvest Natural Resources | — | 3,354 | ||||||
| Purneftegas and affiliated entities | — | 22 | ||||||
Long-term debt | ||||||||
| Harvest Natural Resources | — | 2,500 | ||||||
| YUKOS | 2,500 | — | ||||||
| Minley | 5,000 | 5,000 | ||||||
10
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 15: Related Party Transactions (continued)
Harvest Natural Resources/YUKOS.During 2003 and 2002, Harvest provided insurance on behalf of the Company and personnel services to the Company for a total value of approximately USD 1,087 thousand (2002: USD 1,752 thousand). The remaining portion of the accounts payable balance outstanding relates to services provided in prior reporting periods. As part of the sale of Harvest’s interest in the Company to YUKOS, all balances owing by the Company to Harvest were transferred to YUKOS.
Purneftegasgeologia.During 2003, 2002 and 2001, Purneftegasgeologia and affiliated entities provided services to the Company for a total value of approximately nil, USD 2,414 thousand and USD 4,193 thousand, respectively. Services consisted of drilling, well maintenance and other related work. The Company sold crude oil for a total value of USD 19 thousand and USD 24 thousand during 2003 and 2002, respectively, and materials during 2003 and 2002 for a total value of approximately USD 726 thousand and USD 613 thousand, respectively.
Purneftegas.During 2002 and 2001, Purneftegas and affiliated companies provided well maintenance services and supplies to the Company for a total of approximately USD 312 thousand and USD 248 thousand, respectively. The Company sold materials to Purneftegas and affiliated entities during 2002 for a total value of approximately USD 260 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.
During 2003, interest expense on shareholder loans of USD 99 thousand was incurred with respect to Minley and USD 49 thousand was incurred with respect to Harvest. At 30 September 2003 interest payable to Minley totalled USD 21 thousand (2002: USD 21 thousand) and interest payable to Harvest was USD 65 thousand (2002: USD 14 thousand).
Note 16: 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 government authorities and the Company periodically evaluates its obligations related thereto. As obligations are determined, they are provided for over the estimated remaining lives of the related oil and gas reserves, or recognized immediately, depending on their nature. The existence 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 liabilities that would have a material adverse effect on the financial position, operating results or liquidity of the Company, and that have not been accrued in the financial statements.
11
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 16: Commitments and Contingent Liabilities (continued)
Oilfield licenses.The Company is subject to periodic reviews of its activities by governmental authorities with respect to the requirements of its oilfield licenses. Management of the Company correspond with governmental authorities to agree on remedial actions necessary to resolve any findings resulting from these reviews. Failure to comply with the terms of a license could result in fines, penalties or license limitation, suspension or revocation. The Company’s management believes any issues of non-compliance will be resolved through negotiations or corrective actions without any materially adverse effect on the Company’s financial position or results of operations.
Legal contingencies.The Company is claiming additional deductions relating to the fiscal periods from 1999 to 2001 amounting to approximately RR 330 million (USD 10.8 million). Management believe these deductions are permitted for companies operating in the northern regions of the Russian Federation and also deductions for certain interest paid during that period. Although the Company was successful in the initial hearing before the courts, the tax authorities have continued to challenge the Company’s position. As at 30 September 2003, the Company has not recorded any benefit relating to the above claims.
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 2003 and 2002, 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.
12
LLC GEOILBENT
Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)
(expressed in thousands 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 No. 69”), this section provides supplemental information on the Company’s 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 2003 | 30 September 2002 | 30 September 2001 | |||||||||
| Development costs | 10,217 | 25,290 | 33,774 | |||||||||
| Exploration costs | 3,040 | 1,465 | 6,100 | |||||||||
Total costs incurred in oil and natural gas acquisition, exploration, and development activities | 13,257 | 26,755 | 39,874 | |||||||||
TABLE II — Capitalized costs related to oil and natural gas producing activities:
| As at | As at | |||||||
| Thousand of US Dollars | 30 September 2003 | 30 September 2002 | ||||||
| Proved property costs | 302,214 | 277,659 | ||||||
| Costs excluded from amortisation | — | 800 | ||||||
| Oilfield inventories | 7,442 | 6,905 | ||||||
| Less accumulated depletion and impairment | (212,745 | ) | (92,470 | ) | ||||
Total capitalised costs related to oil and natural gas producing activities | 96,911 | 192,894 | ||||||
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 do not 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.
| Year ended | Year ended | Year ended | ||||||||||
| Thousand of US Dollars | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||
| Oil and natural gas sales | 81,987 | 91,291 | 100,768 | |||||||||
| Expenses: | ||||||||||||
| Operating, selling and distribution expenses and taxes other than on income | 47,319 | 49,713 | 47,302 | |||||||||
| Depletion and amortization | 18,278 | 27,168 | 14,918 | |||||||||
| Impairment of oil and gas properties | 95,000 | — | — | |||||||||
| Income tax expense | 6,098 | 5,750 | 11,006 | |||||||||
| Total expenses | 166,695 | 82,631 | 73,226 | |||||||||
Results of operations from oil and natural gas producing activities | (84,708 | ) | 8,660 | 27,542 | ||||||||
13
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)
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.
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 9 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 the Company considers 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.
14
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS RESERVE QUANTITIES
PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)
| Proved reserves-crude oil, | ||||||||||||
| condensate and natural gas | Year ended | Year ended | Year ended | |||||||||
| liquids (MBbls) | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||
Proved reserves beginning of year | 74,575 | 87,259 | 95,924 | |||||||||
| Revisions of previous estimates | 1,580 | (10,163 | ) | (16,454 | ) | |||||||
| Extensions, discoveries and improved recovery | 2,829 | 4,391 | 12,974 | |||||||||
| Production | (5,712 | ) | (6,912 | ) | (5,185 | ) | ||||||
Proved reserves, end of year | 73,272 | 74,575 | 87,259 | |||||||||
Proved developed reserves | 35,344 | 38,824 | 46,052 | |||||||||
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
================================================================================================================
Year ended Year ended Year ended Thousand of US Dollars 30 September 2003 30 September 2002 30 September 20 Future cash inflow 1,416,343 1,381,874 1,277,494 Future production costs (676,419 ) (599,277 ) (739,221 ) Future development costs (107,841 ) (119,725 ) (108,882 )
Future net revenue before income taxes 632,083 662,872 429,391 10% annual discount for estimated timing of cash flows (293,965 ) (318,079 ) (190,788 )
Discounted future net cash flows before income taxes 338,118 344,793 238,603 Future income taxes, discounted at 10% per annum (68,126 ) (71,442 ) (30,815 )
269,992 273,351 207,788
15
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)
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
| Year ended | Year ended | Year ended | ||||||||||
| Thousand of US Dollars | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||
Present value at beginning of period | 273,351 | 207,788 | 337,426 | |||||||||
| Sales of oil and natural gas, net of related costs | (60,030 | ) | (69,541 | ) | (54,015 | ) | ||||||
| Revisions to estimates of proved reserves: | ||||||||||||
| Net changes in prices, development and production costs | (16,242 | ) | 225,132 | (107,356 | ) | |||||||
| Quantities | 9,346 | (29,432 | ) | (71,709 | ) | |||||||
| Extensions, discoveries and improved recovery, net of future costs | 3,663 | 5,974 | 55,197 | |||||||||
| Accretion of discount | 34,479 | 23,862 | 41,224 | |||||||||
| Net change of income taxes | 3,316 | 3,367 | 43,994 | |||||||||
| Development costs incurred | 13,257 | 26,468 | 37,953 | |||||||||
| Changes in timing and other | 8,852 | (120,267 | ) | (74,926 | ) | |||||||
Present value at end of period | 269,992 | 273,351 | 207,788 | |||||||||
16
EXHIBIT INDEX
| Exhibits | Description of |
| 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 | Amended and Restated Bylaws | |
| 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. | |
| 4.3 | Rights Agreement between Benton Oil and Gas Company and First Interstate Bank, Rights Agent dated April 28, 1995. | |
| 10.1 | Form of Employment Agreements (Exhibit 10.19) | |
| 10.2 | 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 |
| Exhibits | Description of Exhibit | |
| 10.3 | 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 | |
| 10.4 | 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). | |
| 10.5 | 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.). | |
| 10.6 | 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.). | |
| 10.7 | 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.). | |
| 10.8 | 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 | |
| 10.9 | 2001 Long Term Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900)). | |
| 10.10 | Addendum No. 2 to Operating Services Agreement Monagas SUR dated | |
| 10.11 | 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.) | |
| 10.12 | 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.) | |
| 10.13 | 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.) | |
| 10.14 | 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.) | |
| 10.15 | 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.) | |
| 10.16 | 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.) | |
| 10.17 | Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.) | |
| 10.18 | Employment Agreement dated November 17, 2003 between Harvest Natural Resources, Inc. |
| Exhibits | Description of Exhibit | |
| and Karl L. Nesselrode. | ||
| 21.1 | List of subsidiaries. | |
| 23.1 | Consent of PricewaterhouseCoopers | |
| 23.2 | Consent of ZAO PricewaterhouseCoopers Audit - Moscow | |
| 23.3 | Consent of Ryder Scott Company, | |
| 31.1 | Certification of the Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2 | Certification of the Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.1 | Certifications accompanying the annual report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |