UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, | ||||
2004 | ||||
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.
Delaware | 77-0196707 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |
Houston, Texas | ||
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code:(281) 579-6700899-5700
15835 Park Ten Place Drive, Suite 115
Houston, Texas 77084
(Former name, former address and former fiscal year, if changed since last report)
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]þ No [ ]o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X]þ No [ ]o
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter, June 27, 2003: $225,487,430.30, 2004: $535,652,892.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practical date. Class: Common Stock, par value $0.01 per share, on March 1, 2004,February 11, 2005, shares outstanding: 35,778,161.37,596,464.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s Proxy Statement for the 20042005 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission, not later than 120 days after the close of the registrant’s fiscal year, pursuant to Regulation 14A, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this annual report.
HARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
HARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
32 | ||||||||
S-1 | ||||||||
Indemnification Agreement | ||||||||
Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement | ||||||||
Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement | ||||||||
Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement | ||||||||
List of Subsidiaries | ||||||||
Consent of PricewaterhouseCoopers LLP - Houston | ||||||||
Consent of ZAO PricewaterhouseCoopers Audit-Moscow | ||||||||
Consent of Ryder Scott Company, LP | ||||||||
Certification of CEO pursuant to Section 302 | ||||||||
Certification of CFO pursuant to Section 302 | ||||||||
Certification of CEO pursuant to Section 906 | ||||||||
Certification of CFO pursuant to Section 906 |
1
PART I
Harvest Natural Resources, Inc. (“Harvest” or the “Company”) cautions that any forward-looking statements (as such term is defined in the Private Securities Litigation Reform Act of 1995) contained in this report or made by management of the Company involve risks and uncertainties and are subject to change based on various important factors. When used in this report, the words “budget”, “guidance”, forecast”, “anticipate”, “expect”, “believes”, “goals”, “projects”, “plans”, “anticipates”, “estimates”, “should”, “could”, “assume” and similar expressions are intended to identify forward-looking statements. In accordance with the provisions of the Private Securities Litigation Reform Act of 1995, we caution you that important factors could cause actual results to differ materially from those in the forward-looking statements. Such factors include theour concentration of our operations in Venezuela, the political and economic risks associated with international operations (particularly those in Venezuela), 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, the permitting 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’s ability to acquire oil and gas properties that meet its objectives, changes in operating costs, overall economic conditions, political stability,instability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, changes in taxes, changes in governmental policy, availability of sufficient financing, changes in weather conditions, and ability to hire, retain and train management and personnel. See Risk Factors included in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.
At the end of Item 1 is a glossary of terms.
Item 1. Business
GeneralExecutive Summary
Harvest Natural Resources, Inc. is an independent energy company engaged in the acquisition, development, production and disposition of oil and gas properties since 1989, when it was incorporated under Delaware law. Over our history, we have acquired and developed significant interests in the Bolivarian Republic of Venezuela (“Venezuela”) and the Russian Federation (“Russia”) and have undeveloped acreage offshore China. OurCurrently, our producing operations are conducted principally through our 80 percent-owned Venezuelan subsidiary, Benton-Vinccler,Harvest Vinccler, C.A. (“Benton-Vinccler”Harvest Vinccler”, formerly Benton Vinccler, C.A.), which operates the South Monagas Unit in Venezuela. From December 14, 2002 through February 6, 2003, no sales
In September 2004, we announced the redemption on November 1, 2004 of all $85 million of our 9.375 percent senior unsecured notes due November 1, 2007 (the “2007 Notes”). In August and September 2004, we purchased West Texas Intermediate (“WTI”) crude oil puts covering 10,000 barrels of oil per day for calendar year 2005 to protect our 2005 cash flow. These puts cost a total of $14.9 million, have an average strike price of $42.20 per barrel and, due to our pricing structure for our Venezuelan oil, production were made becausehave the economic effect of Petroleos de Venezuela, S.A.’s (“PDVSA”) inability to accept ourhedging approximately 20,800 barrels of oil due toper day. During 2004, we drilled ten new wells and re-entered and completed an additional six wells in the national civil work stoppage in Venezuela. While restoring production led to increased workover activitySouth Monagas Unit. Our daily crude oil and higher operating costs, the return performance of the field was within our expectations. On November 25, 2003, we diversified 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 entire 34 percent minority equity investment in LLC Geoilbent (“Geoilbent”), to Yukos Operational Holding Limited, a Russiansales on December 31, 2004, were 29,000 barrels of oil and gas company, for $69.577 million plus $5.5 million as repaymentcubic feet of intercompany loans and outstanding accounts payable owed to us by Geoilbent.gas. SeeItem 7 – Management’s Discussion and Analysis of Financial Conditions and Results of Operationsfor a complete description of these and other events.events during 2004.
As of December 31, 2003,2004, we had total estimated Proved Reserves in the South Monagas Unit, net of minority interest, of 96.4 MMBoe,84.4 million barrels of oil equivalent (“MMBoe”), and a standardized measure of discounted future net cash flow, before income taxes, for total Proved Reserves of $545.3$802 million.
As of December 31, 2003,2004, we had total assets of $374.3$367.5 million. We had cash in excess of long term debt in the amount of $41.9$84.6 million and no long-term debt. We had total revenues of $186.1 million and net cash provided by operating activities of $74.1 million. For the year ended December 31, 2003, we had cash in the amount of $138.7 million and $96.8 million in long-term debt. We had total revenues of $106.1 million and 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 $104.7 million.
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Our business strategy is to identify, acquire, develop and produce large discovered oil and gas fields in Venezuela and Russia. We have more than twelve years of experience in Venezuela and Russia, and have established organizations in both countries. We seek additional opportunities in these two countries and would consider investments in other countries that meet our criteria. In executing our business strategy, we will strive to sustain the current balance sheet strength through:
• | maintaining financial prudence and rigorous investment criteria; | |||
• | maximizing cash flows from existing operations in order to invest in new opportunities; | |||
• | using our experience, skills and cash on hand to acquire new projects; and | |||
• | keeping our organizational capabilities in line with our rate of growth. |
In Venezuela, we seek to deliver maximum operating cash flow through the efficient management of our capital expenditure programs and cost structure. The year 2004 represented our first full year of natural gas production, which allowed us to diversify our revenues and cash flow. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures.
We have significant financial flexibility and substantial cash flow supported by current oil prices and current production levels for both oil and gas. We believe this provides us with the ability to pursue growth opportunities while at the same time maintaining a strong balance sheet. However, we have recently experienced difficulties in Venezuela with getting our budgets approved and obtaining permits from the Ministry of Energy and Petroleum (“MEP”, formerly Ministry of Energy and Mines) and Ministry of Environment, as required, which are critical to our ability to fully execute our drilling program. A continuation of these difficulties or a curtailment of production in Venezuela could adversely affect our production and our ability to pursue growth opportunities.
While we cannot predict the degree to which we will be successful, we continue to evaluate properties in both Venezuela and Russia to find opportunities which meet our focused acquisition criteria. We expect our cash generating capacity to be supported by our new gas production, lower operating expenses and our expected future Uracoa and Bombal drilling programs.
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. SeeItem 7 – Management’s Discussion and Analysis of Financial Conditions and Results of Operationsand other information set forth elsewhere in this Form 10-K for a description of these and other risk factors.
Available Information
We file annual, quarterly and current reports, proxy statements and other documents with the Securities 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’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 us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC athttp://www.sec.gov.www.sec.gov.
We also make available, free of charge on or through our Internet website (http:(http://www.harvestnr.com)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. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Securities Act of 1934 are also available on the website. In addition, we have adopted a Code of Business Conduct and Ethics that applies to all of our employees, including our chief executive officer, principal financial officer and principal accounting officer. The text of the Code of Business 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 Code 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 is to identify, acquire, develop and produce 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 experience in Venezuela and Russia, and have established operating organizations in both countries. We seek additional opportunities in these two countries and in other 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 and Venezuela; and keep our organizational capabilities in line with our rate of growth.
In Venezuela, we intend to deliver more operating cash flow through the efficient management of our capital expenditure programs and cost structure. We completed the first phase of our gas project at the South Monagas Unit in November 2003 on time and within budget and commenced gas sales on November 25, 2003. This is an important milestone of our strategy because it diversifies our revenues and cash flow, and develops vital market outlets to support further development of untapped reserves of natural 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 in discussions with PDVSA for the development of the nearby Isleno Field.
We are seeking to diversify our cash flow outside of Venezuela as events there demonstrated the risks of our concentration in Venezuela when we lost six weeks of production in the first part of 2003. We seek operational and financial 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 evaluate a number of options to invest in known discoveries which remain undeveloped or under-developed. In September 2003, we sold our 34 percent minority equity investment in our Russian company Geoilbent. As a minority interest owner, our continuing investment in Geoilbent was determined to be inconsistent with our objective of investing in properties in which we have operating and financial control.
We intend to continue to identify, acquire and exploit known oil and natural gas fields in our current areas of activity while maintaining our financial strength and flexibility. To accomplish this, we intend to:
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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. SeeItem 7 – Management’s Discussion and Analysis of Financial Conditions and Results of Operationsand other information set forth elsewhere in this Form 10-K for a description of these and other risk factors.
Operations
The following table summarizes our Proved Reserves, drilling and production activity, and financial operating data by principal geographic area at the end of each of the years ending December 31, 2004, 2003 2002 and 2001.2002. All Venezuelan reserves are attributable to an operating service agreement between Benton-VincclerHarvest Vinccler and PDVSAPetroleos de Venezuela S.A. (“PDVSA”) under which all mineral rights are owned by the Government of Venezuela. We own 80 percent of Harvest Vinccler. The reserve information presented below is net of a 20 percent deduction for the minority interest in Harvest 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. The Venezuelan national civil work stoppage required Harvest 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 the operating service agreement pursuant to the force majeure provisions of the agreement.
Harvest Vinccler | ||||||||||||
Year Ended December 31, | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Dollars in 000’s) | ||||||||||||
RESERVE INFORMATION: | ||||||||||||
Proved Reserves (MBoe) | 84,418 | 96,364 | 102,534 | |||||||||
Discounted future net cash flow attributable to proved reserves, before income taxes | $ | 802,022 | $ | 545,308 | $ | 481,284 | ||||||
Standardized measure of discounted future net cash flows | $ | 544,980 | $ | 366,770 | $ | 317,799 | ||||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||||||
Gross wells drilled | 16 | 3 | 13 | |||||||||
Average daily production (Boe) | 36,418 | 20,130 | 26,598 | |||||||||
FINANCIAL DATA: | ||||||||||||
Oil and natural gas revenues | $ | 186,066 | $ | 106,095 | $ | 126,731 | ||||||
Expenses: | ||||||||||||
Operating expenses and taxes other than on income | 33,297 | 31,445 | 31,608 | |||||||||
Depletion | 34,108 | 19,599 | 22,685 | |||||||||
Income tax expense | 38,968 | 12,158 | 4,866 | |||||||||
Total expenses | 106,373 | 63,202 | 59,159 | |||||||||
Results of operations from oil and natural gas producing activities | $ | 79,693 | $ | 42,893 | $ | 67,572 | ||||||
We disposed of our Russian investments partly in 2002 and partly in 2003. LLC Geoilbent (“Geoilbent”) and Arctic Gas Company (“Arctic Gas”) were accounted for under the equity method and were included at their respective ownership interests in our consolidated financial 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 and 20012002 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002, and 2001, and from Arctic Gas, until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001.2002.
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. We have 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 accounted 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 period until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and 2001.
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 | |||||
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Geoilbent | ||||||||
Year Ended September 30, | ||||||||
2003 | 2002 | |||||||
(Dollars in 000’s) | ||||||||
RESERVE INFORMATION: | ||||||||
Proved Reserves (MBbls) | (a | ) | 25,356 | |||||
Discounted future net cash flow attributable to proved reserves, before income taxes | (a | ) | $ | 117,229 | ||||
Standardized measure of discounted future net cash flows | (a | ) | $ | 92,939 | ||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||
Gross development wells drilled | (a | ) | 6 | |||||
Net development wells drilled | (a | ) | 2 | |||||
Average daily production (Bbls) | 5,242 | 6,438 | ||||||
FINANCIAL DATA: | ||||||||
Oil and natural gas revenues | $ | 27,876 | $ | 31,039 | ||||
Expenses: | ||||||||
Operating, selling and distribution expenses and taxes other than on income | 16,088 | 16,902 | ||||||
Depletion | 6,215 | 9,237 | ||||||
Write-down of oil and gas properties | 32,300 | — | ||||||
Income tax expense | 2,073 | 1,955 | ||||||
Total expenses | 56,676 | 28,094 | ||||||
Results of operations from oil and natural gas producing activities | $ | (28,800 | ) | $ | 2,945 | |||
As of December 31, 2001, weWe owned, free of any sale and transfer restrictions, until it was sold on April 12, 2002, 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),financial operating data for the period.
Arctic Gas Company | ||||
Year Ended | ||||
September 30, 2002 | ||||
(Dollars in 000’s) | ||||
RESERVE INFORMATION: | ||||
Proved Reserves (MBoe) | (a | ) | ||
Discounted future net cash flow attributable to proved reserves, before income taxes | (a | ) | ||
Standardized measure of discounted future net cash flows | (a | ) | ||
DRILLING AND PRODUCTION ACTIVITY: | ||||
Gross wells reactivated | (a | ) | ||
Average daily production (Bbls) | 189 | |||
FINANCIAL DATA: | ||||
Oil and natural gas revenues | $ | 3,554 | ||
Expenses: | ||||
Selling and distribution expenses | 1,429 | |||
Operating expenses and taxes other than on income | 1,673 | |||
Depletion | 139 | |||
Income tax expense | 19 | |||
Total expenses | 3,260 | |||
Results of operations from oil and natural gas producing activities | $ | 294 | ||
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drilling and production activity, and financial operating data for the period until it was sold on April 12, 2002 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 | ) | |||
South Monagas Unit, Venezuela (Benton-Vinccler)(Harvest Vinccler)
General
In July 1992, we and Venezolana de Inversiones y Construcciones Clerico, C.A., a Venezuelan construction and engineering company (“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,Harvest Vinccler, our 80 percent-owned subsidiary. The remaining 20 percent of the outstanding capital stock of Benton-VincclerHarvest Vinccler is owned by Vinccler. Through our majority ownership of stock in Benton-Vinccler,Harvest Vinccler, we make all operational and corporate decisions related to Benton-Vinccler,Harvest Vinccler, subject to certain super-majority provisions of Benton-Vinccler’sHarvest Vinccler’s charter documents related to:
Ÿmergers; | ||||
Ÿconsolidations; | ||||
Ÿsales of substantially all of its corporate assets; | ||||
Ÿchange of business; and | ||||
Ÿsimilar major corporate events. |
Vinccler has an extensive operating history in Venezuela. It provided Benton-VincclerHarvest Vinccler with initial financial assistance and significant construction services. Vinccler provided assistance with construction projects, governmental relations and labor relations during 2004 and 2003.
Under the terms of the operating service agreement, Benton-VincclerHarvest Vinccler is a contractor for PDVSA. Benton-VincclerHarvest 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
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ownership of all hydrocarbons in the fields. In addition, PDVSA maintains full ownership of equipment and capital infrastructure following its installation.
The operating service agreement provides for Benton-VincclerHarvest Vinccler to receive an operating fee for each barrel of crude oil delivered. It also provides Benton-VincclerHarvest 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-VincclerHarvest Vinccler has approximated 48 percent of West Texas Intermediate crude oil (“WTI”) price.
In September 2002, Benton-VincclerHarvest 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. NaturalFor 2004, natural gas sales began in November 2003 and were averaging 70-80 MMcfaveraged 85 million cubic feet (“MMcf”) per day by the end of the year.day. In addition, Benton-VincclerHarvest 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 with the quarterly volume of such sales based on quarterly natural gas sales multiplied by the ratio of 4.5 MMBlsMMBbls to 198 Bcf.
At the end of each quarter, Benton-VincclerHarvest 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-VincclerHarvest Vinccler also prepares invoices for natural gas sales and Incremental Crude Oil. Payment is due under the invoices by the end of the second month after the end of the quarter. Invoice amounts and payments are denominated in U.S. dollars.Dollars. Payments are wire transferred into Benton-Vinccler’sHarvest Vinccler’s account in a commercial bank in the United States.
Benton-Vinccler6
Harvest 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’sHarvest Vinccler’s facilities and at PDVSA’s storage facility.
With respect to gas sales, an initial capital investment of approximately $27 million was required to buildIn 2003, we built and completed 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 completed the fabrication and construction process for the gas pipeline in late 2003. Benton-VincclerHarvest Vinccler borrowed $15.5 million under a project loan for the gas pipeline and related facilities and the remainder wasof the project costs were 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 servicesservice agreement contains requirements for the measurement and quality of the natural gas delivered to PDVSA.
In August 1999, Benton-VincclerHarvest Vinccler sold its power generation facility located in the Uracoa and Tucupita Fields. Concurrently with the sale, Benton-VincclerHarvest 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. Harvest Vinccler has entered into long-term agreements for the leasing of compression and the operation and maintenance of the gas treatment and compression facilities.
Risk Factors
Currently, the production from the South Monagas Unit represents all of our production. This production may be reduced by actions of the Venezuelan government. In addition, political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk. These risk factors and other risk factors are discussed in Item 7,Risk Factors.
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, 2003,2004, Proved Reserves attributable to our Venezuelan operations were 120,455105.5 MBoe (96,364(84.4 MBoe net to Harvest). This represented 100 percent of our Proved Reserves at year end. Benton-VincclerHarvest Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 66 percent of the South Monagas Unit’s Proved Reserves.
7
Drilling and Development Activity
Benton-VincclerHarvest Vinccler drilled threeten oil wells and converted two gas injection wells to producingre-entered an additional six wells in 20032004 and had an average of 111124 wells on production in all fields at year end 2004 in 2003.the Uracoa Field.
Uracoa Field
Benton-VincclerHarvest Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field. There are currently 90 oil and gas producing wells in the field.
Benton-VincclerHarvest Vinccler processes the oil, water and natural gas in the Uracoa central processing unit and ships the processed oil via pipeline to the PDVSA custody transfer point. Benton-VincclerHarvest Vinccler treats and filters produced water, then reinjects it into the aquifer to assist the natural water drive. Benton-VincclerHarvest Vinccler had reinjected produced natural gas into the natural gas cap primarily for storage 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.Harvest 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 MBblsthousand barrels (“MBbls”) of oil per day, 130 MBbls of water per day and injection capacity of 46 MMcf of natural gas per day. Presently allday and storage of up to 75 MBbls of crude oil. All gas presently being sold by Harvest Vinccler is produced from the Uracoa Field.
7
Tucupita Field
There are currently 3130 oil producing wells and sixfive 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 up to 60 MBbls of 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.plant facilities.
Benton-VincclerHarvest Vinccler reinjects 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.
Bombal Field
In 2003, Benton-VincclerThe East Bombal Field was drilled threein 1992, and the wells were suspended until gas sales could take place. There are currently four oil producing 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 the wells were suspended until gas sales could take place. Benton-Vinccler expects to beginplant facilities. Harvest Vinccler began 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 a fee. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA’s inability to accept our oil due to the national civil work stoppage in Venezuela. 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-VincclerHarvest Vinccler has a highly skilled staff of 189219 local employees and four expatriates and has also formed successful and supportive relationships with local government agencies and communities.
Benton-Vincclertwo expatriates. Harvest 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 for local communities within the South Monagas Unit.
Health, Safety and Environment
Benton-Vinccler’sHarvest Vinccler’s health, safety and environmental policy is an integral part of its business. Benton-VincclerHarvest Vinccler continually improves its policy and practices related to personnel safety, property protection and
8
environmental management. These improvements can be directly attributed to its efforts in accident prevention programs and the training and implementation of a comprehensive Process Safety Management System.
North Gubkinskoye and South Tarasovskoye, Russia (Geoilbent)
OnIn September 25, 2003, we sold our 34 percent minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus $5.5 million for the repayment of intercompany loans and accounts receivable. SeeNote 98 – Russian Operations.
East Urengoy, Russia (Arctic Gas Company)
Arctic Gas Company was sold in April 2002. SeeNote 98 – Russian Operations.
WAB-21, 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”) 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
8
the subject of a territorial dispute between the People’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with 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 a review of our assets, a third-party conducted an 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 noNo further impairment of the property had been incurred in 2003.is currently required.
Location and Geology
The WAB-21 contract area is located approximately 50 miles southeast of the Dai Hung (Big Bear) Oil Field. The block is adjacent to British Petroleum’s giant natural gas discovery at Lan Tay (Red Orchid) and 100 miles north of Exxon’s Natuna Discovery. The contract area covers several similar structural trends, each with potential for hydrocarbon reserves in possible multiple pay zones.
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 license extensions, with the current extension in effect until May 31, 2005. While no assurance can be given, we believe we will continue to receive license extensions so long as the sovereignty issues persist.
Domestic Operations
We acquired a 100 percent interest in three California State offshore oil and gas leases (“the California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. All capitalizedIn June 2004, we sold our California onshore property, which had a zero carrying value, for net proceeds of $0.6 million. We and other parties may be responsible to the State of California for any remediation costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the onshore property for sale.and the related offshore oil and gas leases.
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:
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Other | Total | |||||||||||||||||||
(in thousands) | Venezuela | Foreign | Foreign | United States | Total | |||||||||||||||
Year ended December 31, 2004 | ||||||||||||||||||||
Oil and gas sales | $ | 186,066 | — | $ | 186,066 | — | $ | 186,066 | ||||||||||||
Total Assets | $ | 309,794 | $ | 385 | $ | 310,179 | $ | 57,307 | $ | 367,486 | ||||||||||
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 |
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 Reserves as of December 31, 20032004 and 20022003 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. The following table sets forth information regarding estimates of Proved Reserves at December 31, 2003.2004, which are all Venezuelan. The Venezuelan information includes reserve information net of a 20 percent deduction for the minority interest in Benton-Vinccler.Harvest Vinccler. All Venezuelan reserves are attributable to an operating service
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agreement between Benton-VincclerHarvest Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela.
Net Crude Oil and Condensate (MBbls) | ||||||||||||
Proved | Proved | |||||||||||
Developed | Undeveloped | Total | ||||||||||
Venezuela | 36,688 | 33,610 | 70,298 | |||||||||
Net Crude Oil and Condensate (MBbls) | ||||||||||||
Proved | Proved | |||||||||||
Developed | Undeveloped | Total | ||||||||||
Venezuela | 36,390 | 26,124 | 62,514 | |||||||||
Net Natural Gas (MMcf) | ||||||||||||
Proved | Proved | |||||||||||
Developed | Undeveloped | Total | ||||||||||
Venezuela | 84,918 | 71,482 | 156,400 | |||||||||
Net Natural Gas (MMcf) | ||||||||||||
Proved | Proved | |||||||||||
Developed | Undeveloped | Total | ||||||||||
Venezuela | 64,718 | 66,708 | 131,426 | |||||||||
Estimates of commercially recoverable oil and natural gas reserves and of the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, such as:
• | historical production from the subject properties; | |||
• | comparison with other producing properties; | |||
• | the assumed effects of regulation by governmental agencies; and | |||
• | assumptions concerning future operating costs, municipal taxes, abandonment costs, development costs, and workover and remedial costs, all of which may vary considerably from actual results. |
All such estimates are to some degree speculative and various classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the commercially recoverable reserves of oil 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 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 4744 percent of our total Proved Reserves were undeveloped as of December 31, 2003.2004. The cost to develop the Proved Undeveloped Reserves is expected to be $65.6$102.8 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:
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• | 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, policies or taxation; and | |||
• | the impact of inflation on costs. |
The timing of actual future net oil and natural gas sales from Proved Reserves as well as the year-end price, and thus their actual present value, can be affected by the timing of the incurrence of expenditures in connection with development of oil and gas properties. The 10 percent discount factor 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. 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 be inaccurate. For the period ending December 31, 2003,2004, we reported $545.3$1,003 million ($802 million net to us) of discounted future net cash flows before income taxes from Proved Reserves based on the SEC’s required calculations.
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Production, Prices and Lifting Cost Summary
In the following table we have set forth by country our net production, average sales prices and average operating expenses for the years ended December 31, 2004, 2003 2002 and 2001.2002. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership) and Arctic Gas (39 percent ownership not subject to any sale or transfer restrictions at December 2001), which are accounted for under the equity method, have been included at their respective ownership interest in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, our results of operations for the years ended December 31, 2004, 2003 2002 and 20012002 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and 2001 and from Arctic Gas until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001.2002.
Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
2003 | 2002 | 2001 | 2004 | 2003 | 2002 | |||||||||||||||||||
Venezuela | ||||||||||||||||||||||||
Crude Oil Production (Bbls) | 7,347,399 | 9,708,295 | 9,777,516 | 8,152,261 | 7,347,399 | 9,708,295 | ||||||||||||||||||
Natural Gas Production (MMcf) | 2,660,241 | — | — | |||||||||||||||||||||
Natural Gas Production (Mcf) | 31,059,416 | 2,660,241 | — | |||||||||||||||||||||
Average Crude Oil Sales Price ($per Bbl) | $ | 14.07 | $ | 13.08 | $ | 12.52 | $ | 18.90 | $ | 14.88 | $ | 13.08 | ||||||||||||
Average Natural Gas Sales Price ($per MMcf) | $ | 1.03 | — | — | ||||||||||||||||||||
Average Natural Gas Sales Price ($per Mcf) | $ | 1.03 | $ | 1.03 | — | |||||||||||||||||||
Average Operating Expenses ($per Boe) | $ | 4.00 | $ | 3.26 | $ | 4.30 | $ | 2.50 | $ | 4.00 | $ | 3.26 | ||||||||||||
Russia | ||||||||||||||||||||||||
Geoilbent | ||||||||||||||||||||||||
Net Crude Oil Production (Bbls) | 1,913,187 | 2,349,916 | 1,762,814 | |||||||||||||||||||||
Net Crude Oil production (Bbls) | (d | ) | 1,913,187 | 2,349,916 | ||||||||||||||||||||
Average Crude Oil Sales price ($per Bbl) | $ | 14.52 | $ | 13.21 | $ | 19.51 | (d | ) | $ | 14.52 | $ | 13.21 | ||||||||||||
Average Operating Expenses ($per Bbl) | $ | 2.83 | $ | 2.09 | $ | 2.17 | (d | ) | $ | 2.83 | $ | 2.09 | ||||||||||||
Arctic Gas | ||||||||||||||||||||||||
Net Crude Oil Production (Bbls) | (c | ) | (c | ) | 183,087 | (e | ) | (e | ) | (e | ) | |||||||||||||
Average Crude Oil Sales price ($per Bbl) | (c | ) | (c | ) | $ | 21.93 | (e | ) | (e | ) | (e | ) | ||||||||||||
Average Operating Expenses ($per Bbl) | (c | ) | (c | ) | $ | 7.42 | (e | ) | (e | ) | (e | ) |
(a) | Information represents 100 percent of production. | |||
(b) | Average crude oil sales price before hedging activity. | |||
(c) | Information represents our ownership interest. | |||
(d) | Geoilbent was sold on September 25, 2003. | |||
(e) | Arctic Gas was sold on April 12, 2002. |
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Regulation
General
Our operations are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:
• | 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; | |||
• | changes in administrative regulations and the interpretation and application of such rules and | |||
• | changes in contract interpretation and policies of contract adherence. |
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
11
of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.
Venezuela
On February 5, 2003, Venezuela imposed currency controls and created the Commission for Administration of Foreign Currency 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. dollarDollar and restrict the ability to exchange Venezuelan Bolivars for U.S. dollarsDollars and vice versa. Initially the exchange rate was set at 1,600 Venezuelan Bolivars for each U.S. dollar.Dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar.Dollar. Oil companies such as Benton-VincclerHarvest Vinccler are allowed to receive payments for oil sales in U.S. dollarsDollars and pay U.S. dollar-denominated debt, dividends andDollar-denominated expenses from those payments. We have substantial cash reserves and do not expect the Venezuelan currency conversion restrictions orrestriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the adjustment in the exchange rate to have a material impact on us at this time.next twelve months.
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-VincclerHarvest Vinccler submits capital budgets to PDVSA for approvalreview, including capital expenditures to comply with Venezuelan environmental regulations. No capital expenditures to comply with environmental regulations were required in 20022003 or 2003. Benton-Vinccler2004. Harvest 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 MinesMEP and Ministry of Environment, as required. Benton-VincclerHarvest Vinccler is also subject to income, municipal and value-added taxes, and must file certain monthly and annual compliance reports with the national tax administration and with various municipalities.
Drilling and Undeveloped Acreage
For acquisitions of leases and producing properties, development and exploratory drilling, production facilities and additional development activities such as workovers and recompletions, we spent approximately (excluding our share of capital expenditures incurred by equity affiliates) $39.2 million, $58.3 million and $50.6 million in 2004, 2003 and $43.9 million in 2003, 2002, and 2001, respectively. Included in these numbers is $33.5 million, $43.6 million $44.3 million and $28.0$44.3 million for the development of Proved Undeveloped Reserves in 2004, 2003 2002 and 2001,2002, respectively.
We have drilled or participated through our equity affiliate in the drilling of wells as follows:
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Year Ended December 31, | ||||||||||||||||||||||||
2004 | 2003 | 2002 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Wells Drilled: | ||||||||||||||||||||||||
Exploration: | ||||||||||||||||||||||||
Dry hole | — | — | — | — | 1 | 0.4 | ||||||||||||||||||
Development: | ||||||||||||||||||||||||
Crude oil | 16 | 12.8 | 3 | 2.4 | 18 | 12.0 | ||||||||||||||||||
Total | 16 | 12.8 | 3 | 2.4 | 19 | 12.4 | ||||||||||||||||||
Average Depth of Wells (Feet) | 5,443 | 6,095 | 7,341 | |||||||||||||||||||||
Producing Wells(1): | ||||||||||||||||||||||||
Crude Oil | 124 | 99.2 | 111 | 88.8 | 258 | 158.2 |
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.
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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, 2003:2004:
Developed | Undeveloped | Developed | Undeveloped | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
Venezuela | 11,166 | 8,933 | 146,677 | 117,342 | 11,726 | 9,381 | 146,117 | 116,894 | ||||||||||||||||||||||||
China | — | — | 7,470,080 | 7,470,080 | — | — | 7,470,080 | 7,470,080 | ||||||||||||||||||||||||
Total | 11,166 | 8,933 | 7,616,757 | 7,587,422 | 11,726 | 9,381 | 7,616,197 | 7,586,974 | ||||||||||||||||||||||||
Competition
We encounter strongsubstantial competition from major oil and gas companies and independent operators in acquiring properties and leases for the exploration and development of crude oil and natural gas. The principal competitive factors in the acquisition of such oil and gas properties include staff and data necessary to identify, investigate and purchase such properties, and the financial resources necessary to acquire and develop such properties.properties, and access to local partners and governmental entities. Many of our competitors have influence, financial resources, staffs, data resources and facilities substantially greater than ours.
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.position, results of operations and cash flows.
Employees
At December 31, 2003,2004, we had 1819 full-time employees. Harvest Vinccler had 219 employees augmentedand our Moscow office had 16 employees. We augment our staffs from time to time with independent consultants, as required. Benton-Vinccler had 189 employees and our Moscow office had 14 employees.
Title to Developed and Undeveloped Acreage
All Venezuelan reserves are attributable to an operating service agreement between Benton-VincclerHarvest Vinccler and PDVSA, under which all mineral rights are owned by the Government of Venezuela.
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The WAB-21 petroleum contract lies within an area which is the subject of a territorial dispute between the People’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with 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.
Item 2. Properties
In July 2001,April 2004, we leasedsigned a ten-year lease for office space in Houston, Texas, for three years for approximately $11,000$17,000 per month. We leasemoved into the new space in August 2004. In addition, Harvest Vinccler leased new office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively. We leased 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expiresexpired in December 2004. We have subleased all of the office space in California for rents that approximateapproximated our lease costs. See also “Item 1 – Business” for a description of our oil and gas properties and reserves.
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Item 3. Legal Proceedings
Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler,Harvest 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.
Uracoa Municipality Tax Assessments. In July 2004, Harvest Vinccler received three tax assessments from a tax inspector for the Uracoa municipality in which part of the South Monagas Unit is located. A protest to the assessments was filed with the municipality, and in September 2004 the tax inspector responded in part by affirming one of the assessments and issuing a payment order. Harvest Vinccler has filed a motion with the tax court in Barcelona, Venezuela, seeking to enjoin the payment order and dismiss the assessment. We dispute all of the tax assessments and believe we have a substantial basis for our positions.
Item 4. Submission of Matters to a Vote of Security Holders
None.
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PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our Common Stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HNR”. As of December 31, 2003,2004, there were 35,674,66036,779,409 shares of common stock outstanding, with approximately 808698 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 | 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 | |||||||||||||||
First quarter | 6.58 | 4.40 | Second quarter | 6.90 | 4.20 | |||||||||||||||
Second quarter | 6.90 | 4.20 | Third quarter | 7.17 | 5.58 | |||||||||||||||
Third quarter | 7.17 | 5.58 | Fourth quarter | 10.02 | 6.35 | |||||||||||||||
Fourth quarter | 10.02 | 6.35 | ||||||||||||||||||
2004 | First quarter | 14.25 | 9.48 | |||||||||||||||||
Second quarter | 17.00 | 12.13 | ||||||||||||||||||
Third quarter | 16.60 | 11.54 | ||||||||||||||||||
Fourth quarter | 18.25 | 14.67 |
On March 1, 2004,February 11, 2005, the last sales price for the common stock as reported by the NYSE was $11.68$12.26 per share.
Our policy is to retain earnings to support the growth of our business. Accordingly, our board of directors has never declared a cash dividend on our common stock and our indenture currently restricts the declaration and payment of any cash dividends.stock.
Item 6. 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, 2003.2004. 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 and 19992000 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2002, 2001 2000 and 1999,2000, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001 2000 and 1999.2000.
15
Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||
2003 | 2002 | 2001 | 2000 | 1999 | 2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||||||||||||||||||||
(in thousands, except per share data) | (in thousands, except per share data) | |||||||||||||||||||||||||||||||||||||||
Statement of Operations: | ||||||||||||||||||||||||||||||||||||||||
Total revenues | $ | 106,095 | $ | 126,731 | $ | 122,386 | $ | 140,284 | $ | 89,060 | $ | 186,066 | $ | 106,095 | $ | 126,731 | $ | 122,386 | $ | 140,284 | ||||||||||||||||||||
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: | ||||||||||||||||||||||||||||||||||||||||
Operating income | 90,480 | 33,627 | 34,585 | 28,201 | 53,204 | |||||||||||||||||||||||||||||||||||
Net income | 34,360 | 27,303 | 100,362 | 43,237 | 20,488 | |||||||||||||||||||||||||||||||||||
Net income per common share: | ||||||||||||||||||||||||||||||||||||||||
Basic | $ | 0.77 | $ | 2.90 | $ | 1.27 | $ | 0.67 | $ | (1.09 | ) | $ | 0.95 | $ | 0.77 | $ | 2.90 | $ | 1.27 | $ | 0.67 | |||||||||||||||||||
Diluted | $ | 0.74 | $ | 2.78 | $ | 1.27 | $ | 0.66 | $ | (1.09 | ) | $ | 0.90 | $ | 0.74 | $ | 2.78 | $ | 1.27 | $ | 0.66 | |||||||||||||||||||
Weighted average common shares outstanding Basic | 35,332 | 34,637 | 33,937 | 30,724 | 29,577 | |||||||||||||||||||||||||||||||||||
Weighted average common shares outstanding | ||||||||||||||||||||||||||||||||||||||||
Basic | 36,128 | 35,332 | 34,637 | 33,937 | 30,724 | |||||||||||||||||||||||||||||||||||
Diluted | 36,840 | 36,130 | 34,008 | 30,890 | 29,577 | 38,122 | 36,840 | 36,130 | 34,008 | 30,890 |
Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||
2003 | 2002 | 2001 | 2000 | 1999 | 2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||||||||||||||||||||
(in thousands) | (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 | $ | 367,486 | $ | 374,348 | $ | 335,192 | $ | 348,151 | $ | 286,447 | |||||||||||||||||||||||||
Long-term debt, net of current maturities | 96,833 | 104,700 | 221,583 | 213,000 | 264,575 | — | 96,833 | 104,700 | 221,583 | 213,000 | ||||||||||||||||||||||||||||||
Stockholders’ equity (deficit)(1) | 199,713 | 171,317 | 67,623 | 12,904 | (17,178 | ) | ||||||||||||||||||||||||||||||||||
Stockholders’ equity(1) | 243,189 | 199,713 | 171,317 | 67,623 | 12,904 |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Business Strategy We intend to continue to identify, acquire and exploit known oil and natural gas fields in our current areas of interest and possibly other areas while maintaining our financial strength and flexibility. To accomplish this, we intend to:
16 maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure.
Risk Factors In addition to the other information set forth elsewhere in thisForm 10-K, the following factors should be carefully considered when evaluating us. Our Under the operating service agreement Harvest Vinccler submits an annual budget to PDVSA for review and comment. Harvest Vinccler submitted to PDVSA its 2005 budget which provided for a $68 million drilling and facilities program. Under the terms of the operating service agreement this budget was deemed approved by PDVSA in November 2004. However, on December 17, 2004, Harvest Vinccler received letters from PDVSA seeking to reduce the 2005 drilling and facilities budget by over 60 percent and appearing to restrict average crude oil production for 2005 to about 20,400 barrels a day. At about the same time, Harvest Vinccler began to experience delays in the receipt of permits to drill new wells pursuant to its budget. In accordance with established procedures, Harvest Vinccler submitted requests to PDVSA to obtain permits from MEP for the drilling of eight wells. Only one of those requests was forwarded to the MEP. As a consequence of these delayed drilling permits, Harvest Vinccler began to run out of approved locations to continue its two-rig drilling program. On January 11, 2005, Harvest Vinccler formally notified one of its rig contractors that it would not be renewing its drilling contract and placed the rig on standby until January 29, 2005. Also, on January 11, 2005, Harvest Vinccler gave a thirty-day termination notice to the other rig company. On January 18, 2005, we announced that Harvest Vinccler was suspending its drilling program. In recent months, Harvest Vinccler has also experienced some operational interruptions in deliveries to PDVSA, although not of such a magnitude or duration as to affect production. It has been reported that PDVSA has also sought to cut the budgets between 30 percent and 90 percent of the other 31 active operating service agreements in Venezuela. In addition, Rafael Ramirez, the President of PDVSA and Minister of MEP, has stated that PDVSA wants to renegotiate the terms of the operating service agreements as they are too costly, and that five or six of the operating service agreements have serious problems. It has been reported that one of these agreements is the South Monagas Unit operating service agreement held by Harvest Vinccler. Mr. Ramirez has also said that PDVSA will honor its contracts. Collectively, these actions by the Venezuelan Government and PDVSA create a risk that our production will be reduced. Currently, Harvest Vinccler’s production has not been reduced, but if it is not allowed to conduct its drilling and facilities program, or if that program is restricted, then we will not meet our production forecasts and, over time, existing levels of production and available reserves will decline. While we believe such actions are not in accord with the operating service agreement, we and Harvest Vinccler are in discussions with Venezuelan officials and PDVSA to determine if these issues can be resolved through a mutually acceptable agreement. While we are hopeful of achieving a business solution, no assurance can be given that we will succeed or that the situation will not continue for an extended period of time. While we have substantial cash reserves, a prolonged curtailment of production or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition, results of operations and cash flows. 17 Political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk.Political and economic uncertainty is very high in Venezuela. Following the national work stoppage, President Chavez prevailed in a recall referendum. In addition, PDVSA has been reorganized a number of times, most recently in January 2005. The current President of PDVSA is
Acquiring new oil projects in Venezuela depends upon our ability to meet the requirements of the Organic Hydrocarbon Law.New oil projects in Venezuela are governed by the Organic Hydrocarbon Law, which requires that such projects be carried out through incorporated joint ventures with majority ownership by governmental entities. It is our understanding that the MEP is still defining the methodology for the application of this law. While we
Our strategy to focus on Russia carries deal execution, operating, financial, legal and political
Operations in areas outside the U.S. are subject to various risks inherent in foreign operations, and our strategy to primarily focus on Venezuela and Russia limits our country risk diversification.Our operations in areas outside the U.S. are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation
The loss of key personnel could adversely affect our ability to successfully execute our strategy.We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to execute our business strategy. Loss of one or more key individuals in the organization could hamper or delay achieving our strategy.
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 Our current and future revenue is subject to concentrated 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 companies or governments. Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela continues to be considered a highly inflationary economy. Results of operations in that country are measured in U.S. Dollars with all currency gains or losses 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 Oil price declines and volatility could adversely affect our revenue, cash flows and profitability. Prices for oil fluctuate widely. The average price we received for oil in Venezuela increased to $18.90 per Bbl for the year ended December 31, 2004, compared with $14.07 per Bbl for the year ended December 31,
Lower oil and 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” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10 percent,
plus the lower of cost or fair market value of unproved properties. The estimated future net cash flows include the impact of effective hedging activity as applicable. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down”. This charge does not impact cash flow from operating activities, but does reduce stockholders’ equity. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. 19 includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year 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 SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. SeeOur only source of production may be reduced by actions of the Venezuelan Government. 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 At December 31, 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 SEC 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, policies 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 SEC 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. In general, production rates and remaining reserves from oil and gas properties decline 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.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 20 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:
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. 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 and discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We cannot predict the continued availability of insurance at premium levels that justify its purchase. Competition within the industry may adversely affect our operations. We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies for the acquisition of desirable oil and gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours. Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations. Our oil and natural gas operations are subject to various foreign governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated 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.
Results of Operations We include the results of operations of You should read the following discussion of the results of operations for each of the years in the three-year period ended December 31, 21 We have presented selected expense items from our consolidated income statement as a percentage of revenue in the following table:
Years ended December 31, 2004 and 2003 Net income for 2004 was $34.4 million, or $0.90 per diluted share, compared with $27.3 million, or $0.74 per diluted share for 2003. Our results of operations for 2004 primarily reflected the results for Harvest-Vinccler in Venezuela, which accounted for all of our production and oil and gas sales revenue. Oil revenue per barrel increased 34 percent (from $14.07 in 2003 to $18.90 in 2004) and oil sales quantities increased 11 percent (from 7.3 MBbls of oil in 2003 to 8.2 MBbls of oil in 2004) during 2004 compared with 2003. Natural gas sales quantities for 2004 from Venezuela were 31.1 Bcf. Revenue for 2004 includes 0.7 MBbls of oil at a $7.00 fixed price associated with the gas sales contract. Our revenues increased $80.0 million, or 75 percent, during 2004 compared with 2003. This was due to the addition of a full year of natural gas sales ($29.3 million), higher oil volumes ($7.7 million) and higher crude oil prices ($43.0 million). Our sales quantities for 2004 from Venezuela were 13.3 MBoe compared with 7.8 MBoe in 2003. The increase in sales quantities of 5.5 MBoe, or 71 percent, was due to a full year of natural gas production. Crude oil volumes for 2004 were also higher as 2003 was affected by the shut-in of the production in Venezuela from December 2002 to February 2003 due to the national work stoppage. Our operating expenses increased $2.4 million, or 8 percent, for 2004 compared with 2003. This was primarily due to higher production volumes, higher workover and maintenance programs and increased insurance costs. Depletion, depreciation and amortization increased $14.8 million, or 70 percent, during 2004 compared with 2003 due to increased oil and gas production from Venezuela. Depletion expense per barrel of oil produced from Venezuela during 2004 was $2.56 compared with $2.52 during 2003. The increase was primarily due to increased future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during 2003. General and administrative expenses increased $6.1 million, or 39 percent, for 2004 compared with 2003. This was, in part, due to severance payments for a number of employees paid in the second quarter of 2004, the write-off of project evaluation costs associated with projects in Russia, restricted stock bonuses recorded in the third quarter 2004, additional costs associated with Sarbanes-Oxley compliance and an increase in liability under our deferred compensation plan for directors. An arbitration settlement of $1.5 million was recorded in 2003, and bad debt recoveries of $0.6 million and $0.4 million were recorded in 2004 and 2003, respectively, related to an allowance for uncollectible accounts in prior years. Taxes other than on income increased $2.2 million, or 65 percent, during 2004 compared with 2003. This was primarily due to increased Venezuelan municipal taxes which result from higher oil and gas revenues. Investment income and other increased $0.7 million, or 47 percent, during 2004 compared with 2003. This was due to higher interest rates earned on average cash balances. Interest expense decreased $2.7 million, or 26 percent, during 2004 compared with 2003 due to lower average outstanding debt balances for 2004 compared to 2003. In 2004, we redeemed all $85 million of our 2007 Notes, and we repaid all Bolivar denominated debt in March 2003. Net gain (loss) on exchange rates decreased $1.2 million, or 218 percent, for 2004 compared with 2003. 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. 22 We realized income before income taxes and minority interest of $81.3 million during 2004 compared with income of $71.8 million in 2003. The increase was primarily attributable to higher crude oil and natural gas volumes and an increase in crude oil price in 2004 offset by the sale of our minority equity investment in Geoilbent in 2003. Income tax expense increased $23.6 million due to higher Venezuela pre-tax income. The effective tax rate increased from 13 to 41 percent for 2004 compared with 2003. The rate increase was due to foreign income taxes incurred on profitable foreign operations in 2004. The sale of our minority equity investment in Geoilbent in 2003 was offset by U.S. loss carryforwards. The income before minority interest decreased $14.2 million for 2004 compared with 2003. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by increased production of Harvest Vinccler. Equity in net losses of affiliated companies decreased $28.9 million during 2004 compared to 2003. This was due to the elimination of Geoilbent equity losses on September 25, 2003, the date of its sale. Years ended December 31, 2003 and 2002 Net income for Our results of operations for Our revenues decreased $20.6 million, or 16 percent, during
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 Taxes other than on income decreased $0.7 million, or 17 percent, during Investment income and other decreased $0.7 million, or 32 percent, during 23 balances for Net gain on exchange rates decreased $4.0 million, or 88 percent, for We realized income before income taxes and minority interest of $71.8 million during Equity in net losses of affiliated companies decreased $29.0 million during
Capital Resources and Liquidity The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see Risk Factors). We require capital principally to service
The amount of available capital will affect the scope of our operations and the rate of our growth. On February 5, 2003, the Government of Venezuela fixed the exchange rate between the Bolivar and the U.S. Our ability to Debt Reduction.In September 2004, we announced that the
24 November 1, 2004 and $0.9 million write-off of unamortized debt financing costs. Our repayment of the 2007 Notes triggered an obligation under the terms of Harvest Vinccler’s loans from a Venezuelan commercial bank Working Capital.Our capital resources and liquidity are affected by the 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:
At December 31, Cash Flow from Operating Cash Flow from Investing Activities.During the years ended December 31, The timing and size of capital expenditures for the South Monagas Unit are We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements. Cash Flow from Financing Activities.During the year ended 2004, we irrevocably deposited with the Trustee for our 2007 Notes as trust funds $85.0 million plus accrued interest through November 1, 2004 and a prepayment call premium of $1.3 million to redeem the 2007 Notes on the redemption date. During the same period, Harvest Vinccler repaid $6.4 million of its U.S. Dollar denominated debt. During the year ended 2003, 25 repaid Contractual Obligations.We have a lease obligation of approximately
While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash
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.
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 As noted above underCapital Resources and Liquidity, Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004. We do not expect the currency conversion restrictions or the adjustment in the exchange rate to have a material impact on us 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. With respect to During the year ended December 31, 26 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 Oil and natural gas revenue is accrued monthly based on sales. Each quarter, 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 for China unproved properties are excluded from amortization until the properties are evaluated. At least annually, we evaluate our unproved property for possible impairment. If we abandon all exploration efforts in China where no proved reserves are assigned, all exploration and acquisition costs associated with the country will 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
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, economic changes and 27 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 Our current operations are in Venezuela. The U.S. New Accounting Pronouncements In In December 2004, the FASB issued Statement of Financial Accounting Standard 153 Exchanges on Nonmonetary Assets (“SFAS 153”), an amendment of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. We do not expect SFAS 153 to have a material effect on our consolidated financial position, results of operation or cash flows. In September 2004, the SEC issued Staff Accounting Bulletin 106 (“SAB 106”) which provides guidance regarding the interaction of SFAS 143 with the calculation of depletion and the full cost ceiling test of oil and gas properties under the full cost accounting rules of the SEC. The guidance provided in SAB 106 is not expected to have a material effect on our consolidated financial position, results of operation or cash flows. In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”) Consolidation of Variable Interest Entities, which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the
majority of the risks or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (“FIN 46R”), to clarify some of the provisions of FIN 46, 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 28 Item 7A. Quantitative and Qualitative Disclosures About Market Risk We are exposed to market risk from adverse changes in oil and natural gas prices, interest rates and foreign exchange Oil Prices As an independent oil producer, our revenue, other income 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. Interest Rates Total Foreign Exchange For the Venezuelan operations, oil and gas sales are received under a contract in effect through 2012 in U.S.
Item 8. Financial Statements and Supplementary Data The information required by this item is included herein on pages S-1 through Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures The
Evaluation of Disclosure Controls and Procedures.We have established disclosure controls and procedures to ensure that material information relating to us, including our Based on their evaluation as of December 31, Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the Internal Control Integrated Framework, our management concluded that
None. 30 PART III Item 10. Directors and Executive Officers of the Registrant Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the Item 11. Executive Compensation Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Please refer to the information under the caption “Stock Ownership” in our Proxy Statement for the Item 13. Certain Relationships and Related Transactions Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the Item 14. Principal Accounting Fees and Services Please refer to the information under the caption “Independent
PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
33
(b) Reports on Form 8-K On On
REPORT OF INDEPENDENT To the Board of Directors We have completed an integrated audit of Harvest Natural Resources, Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below. Consolidated financial statements and financial statement schedule In our opinion, the consolidated financial statements listed in the index appearing under Item As discussed in Note 1, the Company changed its method of accounting for employee stock-based compensation to the fair value based method effective January 1, 2003. Internal control over financial reporting Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PricewaterhouseCoopers LLP
S-1 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
See accompanying notes to consolidated financial statements. S-2 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
See accompanying notes to consolidated financial statements. S-3 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
See accompanying notes to consolidated financial statements. S-4 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
See accompanying notes to consolidated financial statements. S-5 Supplemental Schedule of Noncash Investing and Financing Activities: During the year ended December 31, 2004, we issued 0.1 million shares of restricted stock valued at $1.2 million and we wrote-off $0.9 million of unamortized debt financing costs in connection with the redemption and discharge of the 9.375 percent senior unsecured notes due November 1, 2007. For the During the year ended December 2004, the holders of our warrants elected to exercise 45,000 warrants on a cashless basis. This resulted in the issuance of 34,054 shares which are held as treasury stock at cost. See accompanying notes to consolidated financial statements. S-6 HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES Note 1 Organization Harvest Natural Resources, Inc. is engaged in the exploration, development, production and management of oil and gas properties. We conduct our business principally in Venezuela 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 accounted for our investment in LLC Geoilbent (“Geoilbent”) and Arctic Gas Company (“Arctic 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). Reporting and Functional Currency The U.S. Revenue Recognition Oil and natural gas revenue is accrued monthly based on production and delivery. Each quarter, Cash and Cash Equivalents Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months. Restricted Cash Restricted cash represents cash and cash equivalents used as collateral for financing, letter of credit and loan agreements, and is classified as current or non-current based on the terms of the agreements. Marketable Securities Marketable securities are carried at cost. S-7 Credit Risk and Operations All of our total consolidated revenues relate to operations in Venezuela. During the year ended December 31, Derivatives and Hedging Statement of Financial Accounting Standards No. 133 (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. We had no hedging instruments in place for our 2004 production. In August 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing a WTI crude oil put for 5,000 barrels of oil per day. The put cost was $4.24 per barrel, or $7.7 million, and has a strike price of $40.00 per barrel. In September 2004, Harvest Vinccler hedged an additional portion of its calendar year 2005 oil sales by purchasing a second WTI crude oil put for 5,000 barrels of oil per day. The put cost was $3.95 per barrel, or $7.2 million, and has a strike price of $44.40 per barrel. Due to the pricing structure for our Venezuelan oil, these two puts have the economic effect of hedging approximately 20,800 barrels of oil per day for an average of $18.29 per barrel. These puts qualify under the highly effective test and the mark-to-market loss at December 31, 2004 is included in other comprehensive loss. At December 31, 2004, Accumulated Other Comprehensive Loss consisted of $0.7 million ($0.5 million net of tax) of unrealized losses on our crude oil puts. Oil sales for the year ended 2004 included no losses in settlement of the puts. Oil sales for the year ended 2003 included settlements of $1.7 million as well as the amortization of the put option cost of $7.7
We continue to assess production levels and
Asset Retirement Liability Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” S-8 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.
Accounts and Notes Receivable Allowance for doubtful accounts related to former employee notes at December 31, 2004 and 2003 was $2.8 million and Other Assets Other assets consist of Property and Equipment We follow the full cost method of accounting for oil and gas properties with costs accumulated in cost centers on a country-by-country basis, subject to a cost center ceiling (as defined by the Securities and Exchange Commission [“SEC”]). All costs associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized as The costs of unproved properties are excluded from amortization until the properties are evaluated. At least Excluded costs at December 31,
All capitalized costs (including oilfield inventory and future abandonment costs under SFAS 143) and estimated future development costs 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. S-9 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 $1.9 million, $1.6 million The major components of property and equipment at December 31 are as follows (in thousands):
We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the SEC. The consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downs in 2004 or 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,
S-10
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. Foreign Currency We have significant operations outside of the United States, principally in Venezuela and, until September 25, 2003, a minority equity investment in Russia. The U.S. 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 we do not currently foresee a credit risk associated with these receivables, collection is dependent upon the financial stability of PDVSA. The book values of all financial instruments Comprehensive Income Statement of Financial Accounting Standards No. 130 (“SFAS 130”) requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. We reflected unrealized
Minority Interests We record a minority interest attributable to the minority shareholder of our Venezuela and Barbados subsidiaries. The minority interests in net income and losses are generally subtracted from or added to arrive at consolidated net income. New Accounting Pronouncements In S-11 In December 2004, the FASB issued Statement of Financial Accounting Standard 153 Exchanges of Nonmonetary Assets (“SFAS 153”), an amendment of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. We do not expect SFAS 153 to have a material effect on our consolidated financial position, results of operation or cash flows. In September 2004, the SEC issued Staff Accounting Bulletin 106 (“SAB 106”) which provides guidance regarding the interaction of SFAS 143 with the calculation of depletion and the full cost ceiling test of oil and gas properties under the full cost accounting rules of the SEC. The guidance provided in SAB 106 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows. In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”) Consolidation of Variable Interest Entities, which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (“FIN 46R”), to clarify some of the provisions of FIN 46, 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 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. Reclassifications Certain items in Note 2
Long-Term Debt Long-term debt consists of the following (in thousands):
In November 1997, we issued $115.0 million in 9.375 percent senior unsecured notes due November 1, 2007 (“2007 Notes”), of which we repurchased $30.0 million. S-12 of In March 2001, In October 2002,
Note We have employment contracts with In Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Uracoa Municipality Tax Assessments. In July 2004, Harvest Vinccler received three tax assessments from a tax inspector for the Uracoa municipality in which part of the South Monagas Unit is located. A protest to the assessments was filed with the municipality, and in September 2004 the tax inspector responded in part by affirming one of the assessments and issuing a payment order. Harvest Vinccler has filed a motion with the tax court in Barcelona, Venezuela, seeking to enjoin the payment order and dismiss the assessment. We dispute all of the tax assessments and believe we have a substantial basis for our positions. We are unable to estimate the amount or range of any possible loss. S-13 We are a defendant in or otherwise involved in other litigation incidental to our business. In the opinion of management, there is no such litigation which Note Taxes Other Than on Income
Taxes on Income The tax effects of significant items comprising our net deferred income taxes as of December 31,
The valuation allowance The components of income before income taxes and minority interest are as follows (in thousands):
The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):
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.
At December 31, 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. The amount of deferred taxes on the undistributed earnings cannot be determined at this time. Note In May 2004, our shareholders approved the 2004 Long Term Incentive Plan (the “Plan”). The Plan provides for the issuance of up to 1,750,000 shares of our common stock in satisfaction of exercised stock options, stock appreciation rights (“SARs”) and restricted stock to eligible participants including employees, non-employee directors and consultants of our company or subsidiaries. Under the Plan, no more than 438,000 shares may be granted as restricted stock, and no individual may be granted more than 110,000 shares of restricted stock or 438,000 in options over the life of the Plan. 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. All options granted to date will vest ratably over a three-year period from their dates of grant and expire ten years from grant date. All restricted stock granted to date is subject to a restriction period of 36 months during which the stock will be deposited with the Company and is subject to forfeiture under certain circumstances. The Plan also permits the granting of performance awards to eligible employees and consultants. Performance awards are paid only in cash and are based upon achieving established indicators of performance over an established period of time of at least one year. Performance awards granted under the Plan may not exceed $5.0 million in a calendar year and may not exceed $2.5 million to any one individual in a calendar year. In the event of a change in control, any restrictions on restricted stock will lapse, the indicators of performance under a performance award will be treated as having been achieved and any outstanding options and SARs will vest and become exercisable. In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the “Stock Purchase Plan”) to encourage our directors to acquire a greater proprietary interest in us through the ownership of our common stock. Under the Stock Purchase Plan, each non-employee director could elect to receive shares of our common stock for all or a portion of their fee for serving as a director. The number of shares issuable is equal to 1.5 times the amount of cash compensation due the director divided by the fair market value of the common stock on the scheduled date of payment of the applicable director’s fee. The shares have a restriction upon their sale for one year from the date of issuance. As of December 31, 2002, 337,850 shares had been issued from the plan. The Stock Purchase Plan was terminated by the Board of Directors in September 2002. In July 2001, our shareholders approved the adoption of the 2001 Long Term Stock Incentive Plan. The 2001 Long Term Stock Incentive Plan provides for grants of options to purchase up to 1,697,000 shares of our common stock in the form of Incentive Stock Options and S-15 changes in capitalization, such as stock splits. In the event of a change in control, 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, 2004, 2003
Significant option groups outstanding at December 31,
Of the number outstanding, In connection with our acquisition of Benton Offshore China Company in December 1996, we adopted the Benton Offshore China Company 1996 Stock Option Plan. Under the plan, Benton Offshore China Company is authorized to issue up to 107,571 options to purchase our common stock for $7.00 per share. The plan was adopted in substitution of Benton Offshore China Company’s stock option plan, and all options to purchase shares of Benton Offshore China Company common stock were replaced under the plan by options to purchase shares of our common stock. All options were issued upon the acquisition of Benton Offshore China Company and vested upon issuance. At December 31, In addition to options issued pursuant to the plans, options have been issued to individuals other than our officers, directors or employees at prices ranging from Note The
S-16 Note 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 and gas. Other income from USA and Other is derived primarily from interest earnings on various investments and consulting revenues. Operations included under the heading “Russia” include project evaluation costs and other costs to maintain an office in Russia. Operations included under the heading “USA and Other” include corporate management,
S-17
Note 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 Fields in the Western Siberia region of Russia. Our minority equity investment in Geoilbent was accounted for using the equity 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
Arctic Gas Company On April 12, 2002, we sold our 68 percent equity interest in Arctic Gas. The equity earnings of Arctic Gas have historically been based on a fiscal 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 accounted for our interest in Arctic Gas using the equity method due to the significant influence we exercised over the operating and financial policies of Arctic Gas. Our weighted-average equity interest, for the year ended December 31, 2001 was 39 percent. We recorded as our share in the losses of Arctic Gas $1.5 million
S-18
Note On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then one of three exploration and production affiliates of the national oil company, PDVSA. The operating service agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit. Under the terms of the operating service agreement, In September 2002,
The Venezuelan government maintains full ownership of all hydrocarbons in the fields. We drilled Note We acquired a 100 percent interest in three California State offshore oil and gas leases (“California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. S-19 Note 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”) for the WAB-21 area. The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea, with an option for an additional 1.25 million acres under certain circumstances, and lies within an area which is the subject of a territorial dispute between the People’s Republic of China 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 a review of our assets, a third-party conducted an 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. Note 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.
Note Basic earnings per common share (“EPS”) are 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 36.1 million, 35.3 million An aggregate of
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES Quarterly Financial Data (unaudited) Summarized quarterly financial data is as follows:
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. S-21 TABLE I
TABLE II
TABLE III
TABLE IV 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 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, economic changes and 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. The evaluations of the oil and natural gas reserves as of December 31, 2004, 2003 The tables shown below represent our interests in
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,
Additional 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. 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 and the following Tables based on a fiscal period ending September 30 and, accordingly, results of operations for oil and natural gas producing activities in Russia reflect the TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):
TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
S-27
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.
Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.
S-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.
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the
SCHEDULE II HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Financial Statements and Notes LLC Geoilbent
REPORT OF INDEPENDENT AUDITORS To the Board of Directors and 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 LLC GEOILBENT
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT 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 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 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 The following table provides pro forma information as if SFAS No. 143 has been applied in previous periods:
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 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 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
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
Note 9: Oil and Gas Producing Properties
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 Note 10: Long-term Debt
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 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 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:
The aggregate maturities of long-term debt outstanding at 30 September 2003 are as follows:
Note 11: Taxes Payable
7 LLC GEOILBENT Note 12: Contributed Capital Capital contributions are as follows:
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:
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.
8 LLC GEOILBENT 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:
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:
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:
9 LLC GEOILBENT 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.
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.
10 LLC GEOILBENT 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 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) 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:
TABLE II — Capitalized costs related to oil and natural gas producing activities:
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.
13 LLC GEOILBENT 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 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
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.
15 LLC GEOILBENT TABLE VI — Changes in the standardized measure of discounted future net cash flows from proved reserves
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