UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
(Mark One)
| | | | | |
| | [ X ]þ | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2006
or
| | | | |
| | For the fiscal year ended December 31, 2003 |
| | | | |
| | | | or |
| | []o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File No.: 1-10762 HARVEST NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
| | | |
| Delaware | | 77-0196707 |
(State or other jurisdiction of incorporation or organization) | | 77-0196707
(I.R.S. Employer Identification Number) |
15835 Park Ten Place Drive,1177 Enclave Parkway, Suite 115300 | | |
| Houston, Texas | | 7708477077 |
| (Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code:
(281) 579-6700899-5700Securities 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 is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ
Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ
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.
[ ]þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filero Accelerated Filerþ Non-Accelerated Filero
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange
Act Rule 12b-2)Act). Yes
[X]o No
[ ]State theþ
The aggregate market value of the
registrant’s 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, 2006 was: $503,574,368.
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, 2004,2, 2007, shares outstanding:
35,778,161.37,536,523.
DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant’s Proxy Statement for the 20042007 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
1
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, successful conversion of Venezuelan assets to a mixed company, 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 natural gas properties, risks incumbent to being a minority shareholder in a corporation, 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 natural gas properties that meet its objectives, changes in operating costs, overall economic conditions, political stability, civil unrest, acts of terrorism, currency and exchange risks, currency controls, changes in existing or potential tariffs, duties or quotas, 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. SeeItem 1A - Risk Factors
included in andItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of
Operations.Operations.At the end of Item 1 is a glossary of terms.
Executive Summary
Harvest Natural Resources, Inc. is an independent energy company engaged in the acquisition, exploration, development, production and disposition of oil and natural 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. Ourof the People’s Republic of China (“China”).
Currently, our only producing operationsassets are conducted principally throughin Venezuela. Since 1992, our 80 percent-owned Venezuelan subsidiary, Benton-Vinccler, C.A.Harvest Vinccler S.C.A. (“Benton-Vinccler”Harvest Vinccler”), which operateshas been providing operating services to Petroleos de Venezuela, S.A. (“PDVSA”) for the South Monagas Unit under an Operating Service Agreement (“OSA”). However, beginning in Venezuela. From2005, the government of Venezuela initiated a series of actions to compel companies with operating service agreements to convert those agreements into new companies in which PDVSA would have a majority interest. On March 31, 2006, Harvest Vinccler signed a Memorandum of Understanding (the “MOU”) with two affiliates of PDVSA, Corporación Venezolana del Petroleo S.A. (“CVP”) and PDVSA Petroleo S.A. (“PPSA”), to convert the OSA into a minority interest in Empresa Mixta Petrodelta S.A. (“Petrodelta”). The MOU is subject to certain conditions, including execution of a conversion contract, and Venezuelan government approvals. On August 16, 2006, the MOU was amended to provide for the addition of the Isleño, El Salto and Temblador fields to Petrodelta as additional consideration for our conversion of the OSA to Petrodelta. On December 14, 2002 through February 6, 2003, no sales18, 2006, at our special meeting of the stockholders, the transactions contemplated by the MOU were approved. As of this report, we have not yet obtained the governmental approvals necessary to complete the conversion, and the timing of and probability for such approval is uncertain.
In April 2006, the Venezuelan National Assembly passed legislation terminating all operating service agreements and directing the government to take over the operations carried out by the private companies without prejudice to the incorporation of mixed companies for that purpose. This action, coupled with the unfinished conversion to Petrodelta, has left Harvest Vinccler without a contractual means recognized by the government of Venezuela to address revenues or costs and expenses since March 31, 2006. As a result of this situation, our consolidated financial statements prepared in accordance with generally accepted accounting principals in the1
United States of America (“GAAP”) for the year ended December 31, 2006 do not reflect the net results of our producing operations in Venezuela for the last three quarters of the year. We will not be able to include the results of our Venezuelan oil production were made because of Petroleos de Venezuela, S.A.’s (“PDVSA”) inabilityoperations in our consolidated financial statements until the conversion to accept our oil due toPetrodelta is completed. Although the national civil work stoppage in Venezuela. While restoring production led to increased workover activity and higher operating costs, the return performanceMOU provides that upon completion of the field was within our expectations. On November 25, 2003, we diversified our revenue streamconversion, there will be an adjustment between the parties to obtain the same economic result as if the conversion had been completed on April 1, 2006, this adjustment will not occur until the conversion is completed.
Since signing the MOU, CVP has designated its board members and a General Manager and President for Petrodelta, both of whom influence Harvest Vinccler’s operations and staffing. Harvest Vinccler continues in the day-to-day operations of its properties in Venezuela, and during the last three quarters of 2006, it has accrued cash advances of $36.3 million to fund operations. At the request of PDVSA, Harvest Vinccler invoiced PDVSA for these costs and $21.2 million, representing the second and third quarter advances, have been reimbursed. Harvest Vinccler invoiced PDVSA for fourth quarter advances of $15.1 million in February 2007. In 2006, Harvest Vinccler resolved and substantially paid all of the tax claims made by beginning the saleSENIAT, the Venezuelan income tax authority. Harvest Vinccler paid $73.8 million additional taxes and related interest for the periods of natural gas2001 through first quarter 2006.
At December 31, 2006, Harvest Vinccler had three loans outstanding with two Venezuelan banks for a total of 225 billion Venezuelan Bolivars (“Bolivars”) (approximately $104.7 million). These loans are collateralized by $88.9 million deposited in Venezuela. On September 25, 2003, we closedtwo U. S. banks. The loans were used to meet the SaleSENIAT income tax assessments and Purchase Agreement to sell our entire 34 percent minority equity investment in LLC Geoilbent (“Geoilbent”), to Yukos Operational Holding Limited,related interest, refinance a Russian oil and gas company, for $69.5 million plus $5.5 million as repaymentportion of intercompanyone of the Bolivar loans and outstanding accounts payable owed to us by Geoilbent.fund operating requirements.
See
Item 1 – Business, Operations, Item 1A – Risk Factors,andItem 7 – Management’s Discussion and Analysis of Financial ConditionsCondition and Results of Operationsfor a complete description of these and other
events.events during 2006.
As of December 31,
2003, we had total estimated Proved Reserves in the South Monagas Unit, net of minority interest, of 96.4 MMBoe, and a standardized measure of discounted future net cash flow, before income taxes, for total Proved Reserves of $545.3 million. As of December 31, 2003,2006, we had total assets of $374.3$422.7 million. We had unrestricted cash in excess of long term debt in the amount of $41.9$148.1 million, long-term debt of $67.0 million, total revenues of $59.5 million and net cash used in operating activities of $24.4 million. For the year ended December 31, 2003,2005, we had total assets of $400.8 million. We had cash in the amount of $163.0 million, no long-term debt, total revenues of $106.1$236.9 million and net cash provided by operating activities of $38.5 million,$114.7 million.
Our business strategy is to seek and long-term debtdevelop large known resources in countries perceived as politically challenging. Our strategy is to diversify risk by adding projects in countries other than Venezuela. In executing our business strategy, we strive to:
| • | | maintain financial prudence and rigorous investment criteria; |
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| • | | access capital markets; |
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| • | | create a diversified portfolio of assets; |
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| • | | preserve our financial flexibility; |
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| • | | use our experience, skills and relationships to acquire new projects; and |
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| • | | keep our organizational capabilities in line with our rate of growth. |
While our strategy does not focus on unexplored areas, we will consider appropriate exploration investments on an opportunistic basis.
In Venezuela, our goal, post conversion, is to influence the management and operations of $96.8 million. ForPetrodelta while developing and producing the year ended December 31, 2002, we had total revenuesSMU fields and the Isleño, Temblador and El Salto fields in the most efficient manner. We expect that amounts available for dividends will be distributed to Petrodelta’s owners on a quarterly basis.
We intend to use our available cash to pursue growth opportunities in countries other than Venezuela. However, this strategy is limited by factors including access to additional capital, timing for conversion and restrictions on the use of $126.7 million, net cash provided by operating activitiesa significant portion of $42.6 million, and long-term debt of $104.7 million.our cash.
2
The ability to successfully execute our strategy is subject to significant risks including, among other things, conversion to Petrodelta, operating risks, political risks, legal risks and financial risks. SeeItem 1A – Risk Factors,Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operationsand other information set forth elsewhere in this Annual Report on Form 10-K for a description of these and other risk factors.
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 Fifth100 F Street
NW,NE, 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 at
http://www.sec.gov.www.sec.gov.
We also make available, free of charge on or through our Internet website (http://www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K,
Current Reports on Form 3, 4 and 5, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
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
Corporate 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.,
attentionAttention Investor Relations.
Business Strategy
Our business strategy is
Operations
All of our operations are in Venezuela. Since 2005, Harvest Vinccler has been unable to
identify, acquire, developexecute its facilities and
produce large discovereddrilling program due to actions by the Venezuelan government, and daily production of oil and
natural gas
fields in areas that are being largely avoided by many other oilvolumes have and
gas companies duewill continue to
challenging political and economic circumstances. We have more than ten years of experience in Venezuela and Russia, and have establisheddecline. In 2006, we completed a ten-well workover program to mitigate the normal decline curve. Harvest Vinccler is currently 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 timecomprising the Uracoa, Tucupita 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 forBombal fields (the “SMU fields”) pending the previously developed Temblador Field and the discovered, yet undeveloped, El Salto Field. Under the termscompletion of the Memorandum of Understanding, we can submit a plan of development for developmentconversion of the fields under Venezuela’s Organic Hydrocarbon Law.OSA to Petrodelta. We are also in discussionsbegan the year with PDVSA for the developmentaverage oil deliveries of the nearby Isleno Field.
We are seeking to diversify our cash flow outside22,000 barrels 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 oilper day (“Bopd”) and natural gas deliveries of 56 million cubic feet a day (“MMCFpd”). The fields in our current areas of activity while maintaining our financial strengthcurrently produce approximately 17,000 Bopd and flexibility. To accomplish this, we intend to:
3
37 MMCFpd.
• | | Focus Our Efforts in Areas of Low Geologic Risk.We intend to focus our activities principally in areas of large known but undeveloped or under-developed oil and gas resources. |
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• | | Seek operational and financial control. We desire to control all major decisions for development, production, staffing and financing of each project for a period of time sufficient for us to reap attractive returns on investments. |
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• | | Establish a Local Presence Through Joint Venture Partners and the Use of Local Personnel:We seek to establish a local presence in our areas of operation to facilitate stronger relationships with local government and labor. In addition, using local personnel helps us to take advantage of local knowledge and experience and to minimize costs. In pursuing new opportunities, we will seek to enter at an early stage and find local partners in an effort to reduce our risk in any one venture. |
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• | | Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital expenditure or development commitments at the outset of new projects, but we endeavor to structure such commitments so that we can fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash outlay. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure. |
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• | | Limit Exploration Activities:We do not engage in exploration except in connection with the expansion of an existing reservoir and in that case only where the risks are deemed to be manageable in the context of total cash exposure and probability of success. |
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• | | Maintain a prudent financial plan: We intend to maintain our financial flexibility by maintaining our total debt within average industry debt to capitalization levels, closely monitoring spending, holding significant cash reserves, actively seeking opportunities to reduce our weighted average cost of capital and increasing our liquidity. |
Our ability to successfully execute our strategy is subject to significant risks including, among other things, operating risks, political risks, legal risks and financial risks. 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,Venezuela proved reserves, drilling and production activity, and financial operating data by principal geographic area at the end of each of the years endingended December 31, 2003, 20022006, 2005 and 2001. All2004. The Venezuelan reserves are attributable to an operating service agreementour OSA between Benton-VincclerHarvest Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela. We disposed of our Russian investments partly in 2002 and partly in 2003. Geoilbent and Arctic Gas 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 2001 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.
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.Harvest Vinccler. Drilling and production activity and financial data are reflected without deduction for minority interest. ReservesFor 2004 and 2005, the year-end reserves include production projected through the endtermination of the operating service agreementOSA in 2012. We have submitted a request for extension underIn April 2006, 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 believegovernment unilaterally terminated the two months representing this delay will be added to the original term of our agreement.
OSA.43
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| | | Benton-Vinccler
| | Harvest Vinccler | |
| | | Year Ended December 31,
| | Year Ended | |
| | | 2003
| | 2002
| | 2001
| | 12/31/06 | | 12/31/05 | | 12/31/04 | |
| | | (Dollars in 000’s) | | (Dollars in 000’s) | |
RESERVE INFORMATION | | |
RESERVE INFORMATION: | | |
| Proved Reserves (MBoe) | | 96,364 | | 102,534 | | 83,611 | | | — | | 36,105 | | 84,418 | |
| 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 | | |
| Standardized measure of discounted future net cash flows | | | $ | — | | $ | 329,438 | | $ | 544,980 | |
DRILLING AND PRODUCTION ACTIVITY: | | |
| Gross wells drilled | | 3 | | 13 | | 8 | | | — | | 1 | | 16 | |
| Average daily production (Boe) | | 20,130 | | 26,598 | | 26,788 | | | 29,389 | | 35,732 | | 36,418 | |
FINANCIAL DATA: | | |
| Oil and natural gas revenues | | $ | 106,095 | | $ | 126,731 | | $ | 122,386 | | | $ | 59,506 | | $ | 236,941 | | $ | 186,066 | |
| Expenses: | | |
| Operating expenses and taxes other than on income | | 31,445 | | 31,608 | | 42,175 | | | 9,451 | | 39,969 | | 33,297 | |
| Depletion | | 19,599 | | 22,685 | | 21,175 | | | 9,904 | | 41,175 | | 34,108 | |
| Income tax expense | | 12,158 | | 4,866 | | 9,083 | | |
Income tax expense(a) | | | 20,076 | | 65,943 | | 38,968 | |
| | |
| |
| |
| | | | | | | | |
| Total expenses | | 63,202 | | 59,159 | | 72,433 | | | 39,431 | | 147,087 | | 106,373 | |
| | |
| |
| |
| | | | | | | | |
| Results of operations from oil and natural gas producing activities | | $ | 42,893 | | $ | 67,572 | | $ | 49,953 | | | $ | 20,075 | | $ | 89,854 | | $ | 79,693 | |
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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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| | | |
| |
| | |
| (a) | | Geoilbent was sold on September 25, 2003.Excludes taxes of $50.3 million recorded in 2006 due to the settlement of the SENIAT tax assessments. |
As
Until we complete the conversion to Petrodelta, we will not have reserves to report under SEC guidelines and, accordingly, no reserves are reported as of December 31,
2001,2006. The 2005 reserve information shown above has been reduced from 2004 to exclude reserves formerly classified as proved undeveloped. Under SEC standards for the reporting of oil and natural gas reserves, proved reserves are estimated quantities of crude oil and natural gas “which geological data and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirsunder existing economic and operating conditions.” (Emphasis added). The 2005 quantities of proved reserves have been reduced to remove undeveloped reserves because of the actions taken by the Venezuelan government beginning in 2005. After completion of the conversion to Petrodelta, we
owned, free of any sale and transfer restrictions, 39will report our net 32 percent of
Petrodelta’s proved reserves. This will include the
equity interestsquantities of proved reserves attributable to the three fields to be added to Petrodelta as provided in
Arctic Gas, which we accounted for under the
equity method. The following table presents our proportionate share, free of sale and transfer restrictions, of Arctic Gas’s Proved Reserves (at September 30, 2001),5
MOU.
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 | ) |
| | | |
| | | |
| |
(a) | | Arctic Gas was sold on April 12, 2002. |
South Monagas Unit Venezuela (Benton-Vinccler)
General
In July 1992, we and Venezolana de Inversiones y Construcciones Clerico, C.A., a Venezuelan construction and engineering company (“Vinccler”), signed a 20-year operating service agreement with Lagoven, S.A., an affiliate of PDVSA, to reactivate and further develop the
Uracoa, Tucupita and BombalSMU 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 OSA was one of the original 33 operating service agreements entered into between PDVSA affiliates and private oil companies. Although it is our position that the OSA is still in place and natural gas operationswe continue in the South Monagas Unit are conducted by Benton-Vinccler, our 80 percent-owned subsidiary. The remaining 20 percentday-to-day operations of the outstanding capital stock of Benton-Vinccler is owned by Vinccler. Through our majority ownership of stock in Benton-Vinccler, we makeSMU fields, the Venezuelan government has terminated all operational and corporate decisions related to Benton-Vinccler, subject to certain super-majority provisions of Benton-Vinccler’s charter documents related to:
| | |
|
• | | mergers; |
|
• | | consolidations; |
|
• | | sales of substantially all of its corporate assets; |
|
• | | change of business; and |
|
• | | similar major corporate events. |
Vinccler has an extensive operating history in Venezuela. It provided Benton-Vinccler with initial financial assistance and significant construction services. Vinccler provided assistance with construction projects, governmental relations and labor relations during 2003.
services agreements effective April 2006.
Under the terms of the
operating service agreement, Benton-VincclerOSA, Harvest Vinccler is a contractor for
PDVSA. Benton-Vincclera PDVSA affiliate. Harvest Vinccler is responsible for overall operations of the
South Monagas Unit,SMU fields, including all necessary investments to reactivate and develop the
fields comprising the South Monagas Unit.SMU fields. The Venezuelan government maintains full
6
ownership of all hydrocarbons in the fields. In addition, the PDVSA affiliate maintains full ownership of equipment and capital infrastructure following its installation.
The operating service agreementOSA 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. TheHistorically, our maximum total fee is subject to quarterly adjustments to reflect changes inunder the averageOSA averaged approximately 48 percent of certain world crude oil prices. Since 1992, the maximum total fee received by Benton-Vinccler has approximated 48 percentprice of West Texas Intermediate crude oil (“WTI”) price.
. Under an amendment we signed in August 2005 to limit our fee, the fee has historically averaged approximately 47 percent of the price of WTI. In September 2002, Benton-VincclerHarvest Vinccler and PDVSA signed an amendment to the operating service agreement,OSA, providing for the delivery of up to 198 Bcfmillion cubic feet (“Bcf”) of natural gas through July 2012 at a price of $1.03 per Mcf. Naturalthousand standard cubic feet (“Mcf”). The OSA stipulated that all payments for oil and natural gas sales beganwere to be paid in November 2003U.S. Dollars. Despite these
4
requirements, PDVSA paid the fee for first quarter 2005 deliveries 50 percent in U.S. Dollars and 50 percent in Bolivars. Subsequent quarterly payments for 2005 and the first quarter of 2006 for oil and natural gas deliveries were averaging 70-80 MMcf per dayreceived 75 percent in U.S. Dollars and 25 percent in Bolivars.
Petrodelta
Upon receipt of the Venezuelan government approvals contemplated by the endMOU, Harvest Vinccler and, we believe, HNR Finance B.V. (“HNR Finance”), and CVP will enter into a Contract of Conversion (the “Conversion Contract”). HNR Finance is a Dutch private company with limited liability. HNR Finance owns a 99.9 percent limited partnership interest in Harvest Vinccler, and Harvest Vinccler Ltd., a Cayman Islands exempted company, owns a 0.1 percent general partnership interest in Harvest Vinccler. All of the year. In addition, Benton-Vincclerequity interest in HNR Finance and Harvest Vinccler Ltd. is owned by Harvest Vinccler Dutch Holding B.V., a Dutch private company with limited liability. We own an 80 percent equity interest in Harvest Vinccler Dutch Holding B.V. The remaining 20 percent equity interest is owned by Oil & Gas Technology Consultants (Netherlands) Coöperatie U.A. (“OGTC”). OGTC is controlled by an affiliate of Vinccler.
Upon execution of the Conversion Contract, Petrodelta will be formed. Subject to the conditions of the Conversion Contract, as of the closing date established in the Conversion Contract, the OSA will be cancelled, Harvest Vinccler will transfer substantially all of its tangible assets and contracts, permits and rights related to the SMU fields in Venezuela to Petrodelta, and Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the SMU fields, as well as the Isleño, Temblador and El Salto fields which will have been awarded to Petrodelta. Upon completion of conversion, HNR Finance will have a 40 percent ownership interest in Petrodelta. Since we indirectly own 80 percent of HNR Finance, we will indirectly own a net 32 percent in Petrodelta and Vinccler will indirectly own the remaining eight percent. CVP will own the remaining 60 percent. We have requested CVP to add HNR Finance as a party to the Conversion Contract.
Exploration and production activities under the Conversion Contract will be conducted by Petrodelta for a maximum period of 20 years. Petrodelta will undertake its operations in accordance with the business plan agreed to sellby CVP and Harvest Vinccler which will be set forth in Annex I 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 barrelConversion Contract. Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with the quarterly volumebusiness plan. The business plan may be modified by a favorable decision of the shareholders owning at least 75 percent of the shares of Petrodelta. Harvest Vinccler has proposed a business plan to CVP for Petrodelta, but it has not been formally approved.
Petrodelta will adopt policies and procedures governing its operations, including, among others, policies and procedures for safety, health and environment, contracting, maintenance of insurance, accounting, banking and treasury, and human resources, following the guidelines established by CVP. To the extent possible, such
sales based on quarterly natural gas sales multipliedpolicies and procedures will be consistent with the policies and procedures of PDVSA and the ultimate parent company of Harvest Vinccler. Petrodelta will hire personnel, largely from Harvest Vinccler, and the shareholders will appoint the management of Petrodelta. Harvest Vinccler will transfer or assign its employees requested by the
ratioboard of
4.5 MMBlsdirectors to
198 Bcf. At the endPetrodelta. Harvest Vinccler will fill its share of each quarter, Benton-Vinccler prepares an invoicemanagement positions with employees or secondees to PDVSA based on barrelsHarvest Vinccler. The General Manager of oil accepted by PDVSA during the quarter, using quarterly adjusted contract service fees per barrel. At the end of each quarter, Benton-Vinccler also prepares invoices for natural gas sales and Incremental Crude Oil. Payment is due under the invoicesPetrodelta will be appointed by the endBoard of Directors and will be in charge of the second month after the enddaily management of the quarter. Invoice amountsbusiness of Petrodelta and payments are denominatedwill have the power and duties customary to manage, direct and supervise the accounting of Petrodelta. CVP has the right to nominate the General Manager to Petrodelta while HNR Finance has the right to nominate the Technical and Operations Manager. CVP also has the right to nominate the Manager of Prevention and Loss Control.
Petrodelta will be governed in
U.S. dollars. Payments are wire transferred into Benton-Vinccler’s accountaccordance with the Charter and By-laws of Petrodelta as set forth in
Annex E to the Conversion Contract. Under the Charter and By-Laws, matters requiring shareholder approval may be approved by a
commercial banksimple majority with the exception of certain specified matters which require the approval by the holders of at least 75 percent of the capital stock. These matters include: most changes to the Charter and By-laws; changes in the
United States. Benton-Vinccler has constructed a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s storage facility,capital stock of Petrodelta that would alter the custody transfer point. The operating service agreement specifies that the oil stream may contain no more than one percent base sediment and one percent water. Quality measurements are conducted both at Benton-Vinccler’s facilities and at PDVSA’s storage facility.
With respect to gas sales, an initial capital investmentpercentage participation of approximately $27 million was required to build a 64-mile pipeline with a normal capacityHNR Finance or CVP; any liquidation or dissolution of 70 MMcfPetrodelta; any merger, consolidation or business combination of natural gas per day and a design capacityPetrodelta; disposition 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-Vinccler borrowed $15.5 million under a project loan for the gas pipeline and related facilities and the remainder was funded from existing cash balances and internally generated cash flow. In addition, Benton-Vinccler has entered into long-term agreements for the leasing of compression, and the operation and maintenance of the gas treatment and compression facilities. The operating services agreement contains requirements for the measurement and quality of the natural gas delivered to PDVSA.
In August 1999, Benton-Vinccler sold its power generation facility located in the Uracoa and Tucupita Fields. Concurrently with the sale, Benton-Vinccler entered into a long-term power purchase agreement with the purchaser of the facility to provide for the electrical needs of the field throughout the remaining term of the operating service agreement.
Location and Geology
The South Monagas Unit extends across the southeasternall or any substantial part of the stateassets 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, Proved Reserves attributable to our Venezuelan operations were 120,455 MBoe (96,364 MBoe net to Harvest). This represented 100 percent of our Proved Reserves at year end. Benton-Vinccler has been primarily developing the Oficina sandsPetrodelta, except in the Uracoa Field. The Uracoa Field contains 66 percentordinary course of business; any financing agreement for an amount greater than $10 million; approval or modification of Petrodelta’s financial statements; creation of certain reserve funds; any distribution of dividends or return of paid-in surplus; changes to the South Monagas Unit’s Proved Reserves.
policy regarding dividends and other distributions established by the Charter and By-laws; changes to the75
business plan; changes to the contract for sale and
Development Activity Benton-Vinccler drilledpurchase of hydrocarbons with PPSA; contracts with shareholders or affiliates that are not at market price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to litigation involving more than $1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and designation of a liquidator in the event of the liquidation of Petrodelta.
The Board of Directors of Petrodelta will consist of five directors, three of whom are appointed by CVP, including the President of the Board, and two of whom are appointed by HNR Finance. Decisions of the Board of Directors will be taken by the favorable vote of at least three of its members, except in the case of any decision implementing a decision of the Shareholders’ Meeting relating to any of the matters where a qualified majority is required, in which case, a favorable vote of four members will be required. The Board of Directors has broad powers of administration and disposition expressly granted in the Charter and By-laws of Petrodelta. The powers include: proposing budget and work programs; presenting the annual report to the shareholders; appointing and dismissing personnel; making recommendations regarding financial reserves and utilization of surplus; making proposals on dividends consistent with the By-laws and Charter of Petrodelta; agreeing on contracts consistent with the work programs and budgets; opening and closing bank accounts; make, accept, endorse and guarantee bank drafts and other commercial instruments consistent with work programs and budgets; and implementing policies and procedures of Petrodelta.
The sale of oil wells and converted two gas injection wellsby Petrodelta to producing wellsthe Venezuelan government will be pursuant to a contract for sale and purchase of oil and gas with PPSA. The form of the agreement is set forth in 2003Annex K to the Conversion Contract. Crude oil delivered from the SMU fields to PDVSA will be priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference priced and prevailing market conditions. Natural gas delivered from the SMU fields to PDVSA will be priced at $1.54 per thousand cubic feet. The reference price for crude oil and the price for natural gas produced from the Temblador, El Salto and Isleño fields has not been set under the contract. PPSA will make payment to Petrodelta of each invoice by wire transfer, in United States Dollars (“U.S. Dollars”) in the case of payment for crude oil and natural gas liquids delivered, and in Bolivars in the case of payment for natural gas delivered, in immediately available funds to the bank accounts designated by Petrodelta.
An unofficial English version of the Conversion Contract is attached to our proxy statement filed with the SEC on November 6, 2006 in connection with our special meeting of stockholders to approve the conversion to Petrodelta.
Once the conversion is completed, there will be an adjustment between the parties to obtain the same economic result as if the conversion had
an averagebeen completed on April 1, 2006. The adjustment will take into account the value of
111 wells on productionoil and natural gas produced from April 1, 2006 and the costs incurred by Harvest Vinccler in
all fields in 2003.relation to such production.
South Monagas Unit Fields
Uracoa Field Benton-Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field.
Benton-Vinccler processes the
There are currently 82 oil
water and natural gas
producing wells in the
Uracoa central processing unit and ships the processed oil via pipeline to the PDVSA custody transfer point. Benton-Vinccler treats and filters produced water, then reinjects it into the aquifer to assist the natural water drive. Benton-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. 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.field. The current production facility has capacity to handle 60
MBblsthousand barrels (“MBbls”) of oil per day, 130 MBbls of water per day, and
injection capacitystorage of
46 MMcfup to 75 MBbls of
crude oil. All natural gas
per day. Presently all gaspresently being
solddelivered by Harvest Vinccler is produced from the Uracoa
Field.field.
There are currently
3119 oil producing wells and
sixfive water injection wells at
Tucupita.Tucupita field. The
currentTucupita production facility has capacity to
handleprocess 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
MBblMBbls of oil per day
capacity oil pipeline
constructed in 2001 from
the Tucupita
field to the Uracoa
central processing unit. Benton-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.
plant facilities.
Bombal Field
In 2003, Benton-Vinccler6
The East Bombal field was drilled threein 1992, and currently has one producing well. There are currently two 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 viafluid produced from West Bombal field flows through a six-mile pipeline and is tied into the 31-mile Tucupita oil pipeline to the Uracoa central processing unit. Theplant facilities. Development of the East Bombal Field was drilledfield has been postponed pending completion of the conversion of the OSA to Petrodelta.
Infrastructure and Facilities
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 Harvest Vinccler’s facilities and at PDVSA’s storage facility.
In 2003, we built and completed a 64-mile pipeline with a normal capacity of 70 million cubic feet (“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.
In August 1999, Harvest Vinccler sold its power generation facilities located in
1992,the Uracoa and
Tucupita fields. Concurrently with the
wells were suspended until gas sales could take place. Benton-Vinccler expectssale, Harvest Vinccler entered into a long-term power purchase agreements with the purchaser of the facilities to
begin engineering and design studies in late 2004 with first gas sales expected in 2005. Gas from thisprovide for the electrical needs of the field
will be used to supplement gas production from Uracoa as production there declines.Customers and Market Information
Underthroughout the remaining term of the operating service agreement, allagreement. 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.
The Isleño, Temblador and El Salto Fields
The Isleño, Temblador and El Salto fields to be transferred to Petrodelta after conversion are located in the same geographic area and have the same geology and productive formations as the SMU fields. As with the SMU fields before Harvest Vinccler’s entry in 1992, there had been minimal development activity in the three fields during the last 20 years.
Isleño Field
The Isleño fields were discovered in 1953. Two-dimensional seismic data is available over a portion of the Isleño fields. Seven oil appraisal wells have been drilled in Isleño which have confirmed the presence of commercial oil deposits. The fields are located near existing infrastructure in the SMU Uracoa field. Petrodelta’s business plan projects full development of the Isleño fields over the next three years.
Temblador Field
The Temblador field was discovered in 1936 and developed in the 1940s and the 1950s. Temblador has produced 118 million barrels of oil equivalent (“Boe”) and 64 billion cubic feet of natural gas from 155 wells since 1936. Three-dimensional seismic is available over the entire Temblador field.
El Salto Field
The El Salto field was discovered in 1936. A total of 31 appraisal wells have been drilled identifying nine productive structures and six productive formations. The field has produced less than 1 million Boe and is deliveredcurrently dormant. Three-dimensional seismic data is available over one-third of the El Salto field. The El Salto field has substantial exploration upside from several fault blocks, which have been identified using seismic data but have not yet been confirmed through drilling.
Business Plan of Petrodelta
While the business plan for Petrodelta has not yet been finalized, we envision the plan to
PDVSAcall for
a fee. From December 14, 2002 through February 6, 2003, no sales were made becausethe immediate resumption 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 losssuspended development of
sales could have a material adverse effect on our financial condition.Employees and Community Relations
Benton-Vinccler has a highly skilled staff of 189 local employees and four expatriates and has also formed successful and supportive relationships with local government agencies and communities.
Benton-Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care,the SMU fields as well as additional social investments includingappraisal and development of the purchase of medicinesIsleño, Temblador and medical equipment for local communities within the South Monagas Unit.
El Salto fields. Health, Safety and Environment
Benton-Vinccler’s health, safety and environmental policy is an integral part of its business. Benton-Vinccler continually improves its policy and practices related to personnel safety, property protection and
87
environmental management.
Harvest Vinccler had previously identified and submitted in excess of 20 development wells for approval in the SMU fields. These improvementswells will likely be the immediate focus of the restarted development program in Petrodelta. Concurrently, we envision the timely appraisal and development of the Isleño field and further development of the Temblador field. We believe the Isleño field production can be directly attributedintegrated into the existing Uracoa field infrastructure providing for early production from the field. Temblador field production would be processed at existing field facilities. The El Salto field is believed to its effortscontain substantial undeveloped reserves. Accordingly, we expect to acquire additional three-dimensional seismic and undergo significant appraisal and development in accident prevention programsa timely manner to provide for larger scale development implementation. Overall, production is expected to peak four to six years from commencement of Petrodelta.
Risk Factors
We face significant risks in Venezuela. These risks and
the trainingother risk factors are discussed inItem 1A – Risk FactorsandItem 7 – Management’s Discussion and implementationAnalysis of a comprehensive Process Safety Management System.North GubkinskoyeFinancial Condition and South Tarasovskoye, Russia (Geoilbent)
On 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 repaymentResults of intercompany loans and accounts receivable. SeeNote 9 – Russian Operations.
East Urengoy, Russia (Arctic Gas Company)
Arctic Gas Company was sold in April 2002. SeeNote 9 – Russian Operations.
WAB-21, South China Sea (Benton Offshore China Company) 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
territorialborder 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
territorialborder dispute has lasted for many years, and there has been limited exploration and no development activity in the
WAB-21 area
underdue to the 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 no further impairment of the property had been incurred in 2003. The WAB-21 contract area is located
in the West Wan’an Basin (Nam Con Son) on the South China Sea. Its western edge lies approximately 50 miles southeast of the Dai Hung (Big Bear) Oil Field. The block is
adjacent to
British Petroleum’s giantthe east of significant natural gas
discoverydiscoveries at Lan Tay
(Red Orchid) and
100 miles northLan Do, which are reported to contain two trillion cubic feet of
Exxon’s Natuna Discovery.natural gas. WAB-21 is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas and east of the Dua and Blackbird discoveries that successfully tested oil and gas in 2006. The
WAB-21 contract area covers several similar structural trends
and geological formations, each with potential for hydrocarbon reserves in possible multiple pay
zones.zones similar to the known fields and discoveries.
Drilling and Development Activity Due to the
sovereignty issuesborder dispute 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.Domestic Operations
We acquired a 100 percent interest in three California State offshore oil and gas leases (“2007. While no assurance can be given, we believe we will continue to receive contract extensions so long as the California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. All capitalized costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the onshore property for sale.
border disputes persist.
The following table summarizes our consolidated activities by area. Total Assets represents all assets, including long-lived assets accounted for under the equity method:
98
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | 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, 2003 and 2002 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. The Venezuelan information includes reserve information net of a 20 percent deduction for the minority interest in Benton-Vinccler. All Venezuelan reserves are attributable to an operating service agreement between Benton-Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela.
| | | | | | | | | | | | | |
| | | Net Crude Oil and Condensate (MBbls)
|
| | | Proved | | Proved | | |
| | | Developed
| | Undeveloped
| | Total
|
| Venezuela | | | 36,688 | | | | 33,610 | | | | 70,298 | |
| | | |
| | | |
| | | |
| |
| | | | | | | | | | | | | |
| (in thousands) | | Venezuela | | United States | | Total |
Year ended December 31, 2006 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 59,506 | | | | — | | | $ | 59,506 | |
| Total Assets | | $ | 306,289 | | | $ | 116,422 | | | $ | 422,711 | |
| | | | | | | | | | | | | |
Year ended December 31, 2005 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 236,941 | | | | — | | | $ | 236,941 | |
| Total Assets | | $ | 258,268 | | | $ | 142,530 | | | $ | 400,798 | |
| | | | | | | | | | | | | |
Year ended December 31, 2004 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 186,066 | | | | — | | | $ | 186,066 | |
| Total Assets | | $ | 309,794 | | | $ | 57,692 | | | $ | 367,486 | |
| | | | | | | | | | | | | |
| | | Net Natural Gas (MMcf)
|
| | | Proved | | Proved | | |
| | | Developed
| | Undeveloped
| | Total
|
| Venezuela | | | 84,918 | | | | 71,482 | | | | 156,400 | |
| | | |
| | | |
| | | |
| |
Estimates of commercially recoverable oil and natural gas reserves and of the future net cash flows derived 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 47 percent of our total Proved Reserves were undeveloped as of December 31, 2003. The cost to develop the Proved Undeveloped Reserves is expected to be $65.6 million over the next three years.
Reserve estimates are not constrained by the availability of the capital resources required to finance the estimated development and operating expenditures. In addition, actual future net cash flows will be affected by factors such as:
10
• | | actual production; |
|
• | | oil and natural gas sales; |
|
• | | supply and demand for oil and natural gas; |
|
• | | availability and capacity of gathering systems and pipelines; |
|
• | | changes in governmental regulations or taxation; and |
|
• | | the impact of inflation on costs. |
The timing of actual future net oil and natural gas sales from Proved 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, we reported $545.3 million of discounted future net cash flows before income taxes from Proved Reserves based on the SEC’s required calculations.
Production, Prices and Lifting Cost Summary
In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the period ended March 31, 2006, and years ended December 31, 2003, 20022005 and 2001.2004. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership) and Arctic Gas (39 percent ownership not subject to any sale or transfer restrictions at December 2001), which are accounted for under the equity method, have been included at their respective ownership interest in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, our results of operations for the years ended December 31, 2003, 2002 and 2001 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and 2001 and from Arctic Gas until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001.
| | | | | | | | | | | | | |
| | | Year Ended December 31,
|
| | | 2003
| | 2002
| | 2001
|
Venezuela | | | | | | | | | | | | |
| Crude Oil Production (Bbls) | | | 7,347,399 | | | | 9,708,295 | | | | 9,777,516 | |
| Natural Gas Production (MMcf) | | | 2,660,241 | | | | — | | | | — | |
| Average Crude Oil Sales Price ($per Bbl) | | $ | 14.07 | | | $ | 13.08 | | | $ | 12.52 | |
| Average Natural Gas Sales Price ($per MMcf) | | $ | 1.03 | | | | — | | | | — | |
| Average Operating Expenses ($per Boe) | | $ | 4.00 | | | $ | 3.26 | | | $ | 4.30 | |
Russia | | | | | | | | | | | | |
Geoilbent (a)(b) | | | | | | | | | | | | |
| Net Crude Oil Production (Bbls) | | | 1,913,187 | | | | 2,349,916 | | | | 1,762,814 | |
| Average Crude Oil Sales price ($per Bbl) | | $ | 14.52 | | | $ | 13.21 | | | $ | 19.51 | |
| Average Operating Expenses ($per Bbl) | | $ | 2.83 | | | $ | 2.09 | | | $ | 2.17 | |
Arctic Gas (a)(c) | | | | | | | | | | | | |
| Net Crude Oil Production (Bbls) | | | (c | ) | | | (c | ) | | | 183,087 | |
| Average Crude Oil Sales price ($per Bbl) | | | (c | ) | | | (c | ) | | $ | 21.93 | |
| Average Operating Expenses ($per Bbl) | | | (c | ) | | | (c | ) | | $ | 7.42 | |
| | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2006(a) | | 2005 | | 2004 |
Venezuela(b) | | | | | | | | | | | | |
| Crude Oil Production (Bbls) | | | 1,894,101 | | | | 8,762,687 | | | | 8,152,261 | |
| Natural Gas Production (Mcf) | | | 4,506,094 | | | | 25,677,460 | | | | 31,059,416 | |
Average Crude Oil Sales Price ($per Bbl)(c) | | $ | 28.96 | | | $ | 24.02 | | | $ | 18.90 | |
| Average Natural Gas Sales Price ($per Mcf) | | $ | 1.03 | | | $ | 1.03 | | | $ | 1.03 | |
| Average Operating Expenses ($per Boe) | | $ | 3.49 | | | $ | 3.05 | | | $ | 2.50 | |
| | |
| (a) | | Information represents our ownership interest.Reflects oil and natural gas deliveries through March 31, 2006. |
| |
| (b) | | Geoilbent was sold on September 25, 2003.Information represents 100 percent of production. |
| |
| (c) | | Arctic Gas was sold on April 12, 2002.Average crude oil sales price after hedging activity. |
11
Regulation
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; andlaws relating to the petroleum industry; |
| |
| • | | changes in administrative regulations and the interpretation and application of such rules and regulations.regulations; 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,
sometimes retroactively, for a variety of political, economic, environmental and
9
other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing
business.business and our potential for economic loss.
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.
InitiallyThe Bolivar is not readily convertible into the
exchange rate was set at 1,600 Venezuelan Bolivars for each U.S.
dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar. Oil companies such as Benton-Vinccler are allowed to receive payments for oil sales in U.S. dollars and pay U.S. dollar-denominated debt, dividends and expenses from those payments.Dollar. We 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. Venezuela requires environmental and other permits for certain operations conducted in oil field development, such as site construction, drilling and seismic activities. As a contractor to PDVSA, Benton-Vinccler submits capital budgets to PDVSA for approval including capital expenditures to comply with Venezuelan environmental regulations.foreseeable future.
No capital expenditures to comply with environmental regulations were required in
20022004, 2005 or
2003. Benton-Vinccler also submits requests for permits for drilling, seismic and operating activities to PDVSA, which then obtains such permits from the Ministry of Energy and Mines and Ministry of Environment, as required. Benton-Vinccler2006. Harvest 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)
$58.3$1.5 million,
$50.6$9.0 million and
$43.9$39.2 million in
2003, 20022006, 2005 and
2001,2004, respectively. Included in these numbers is
$43.6 million, $44.3$8.9 million and
$28.0$33.5 million for the development of
Proved Undeveloped Reservesproved undeveloped reserves in
2003, 20022005 and
2001,2004, respectively.
We have
drilled or participated
through our equity affiliate in the drilling of wells as follows:
12
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2006 | | 2005 | | 2004 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Wells Drilled: | | | | | | | | | | | | | | | | | | | | | | | | |
| Development: | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | | — | | | | — | | | | 1 | | | | 0.8 | | | | 16 | | | | 12.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Average Depth of Wells (Feet) | | | — | | | | — | | | | — | | | | 4,349 | | | | — | | | | 5,443 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Producing Wells(1): | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude Oil | | | 103 | | | | 82.4 | | | | 108 | | | | 86.4 | | | | 124 | | | | 99.2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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
arewere conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.
The following table summarizes the developed and undeveloped acreage that we owned, leased or heldhold under operating service agreement or concession as of December 31, 2003:2006:
| | | | | | | | | | | | | | | | | |
| | | Developed
| | Undeveloped
|
| | | Gross
| | Net
| | Gross
| | Net
|
| Venezuela | | | 11,166 | | | | 8,933 | | | | 146,677 | | | | 117,342 | |
| China | | | — | | | | — | | | | 7,470,080 | | | | 7,470,080 | |
| | | |
| | | |
| | | |
| | | |
| |
| Total | | | 11,166 | | | | 8,933 | | | | 7,616,757 | | | | 7,587,422 | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | | | | | | |
| | | Undeveloped |
| | | Gross | | Net |
| China | | | 7,470,080 | | | | 7,470,080 | |
| | | | | | | | | |
Competition10
Title to Undeveloped Acreage
The WAB-21 petroleum contract lies within an area which is the subject of a border dispute between China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with a third party. The border dispute has existed for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the 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.
Competition
We encounter
strongsubstantial competition from major,
national and independent oil and
natural 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
natural 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.
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.
At December 31, 2003, we2006, our Houston office had 18 full-time employees. Harvest Vinccler had 240 employees augmentedand our Moscow and London offices had 11 and 5 employees, respectively. We augment our staffs from time to time with independent consultants, as required. Benton-Vinccler had 189 employees
Item 1A. Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K, the following factors should be carefully considered when evaluating us.
While approved by our stockholders, the conversion of the OSA to Petrodelta may not be completed and we may not recover our investments or be compensated for our services in Venezuela, and our Moscow officeinterests in Venezuela may be unlawfully confiscated by the Venezuelan government.Since April 1, 2006, our operations in Venezuela have continued to be conducted pursuant to the terms of the OSA, which the government no longer recognizes and which it claims is illegal. As such, our future ability to contractually recover all or part of our investments and be compensated for our services depends on completing the process for the conversion of the OSA and transfer of our interests to Petrodelta. If we are unable to convert to Petrodelta, we may not be paid for oil and natural gas produced after March 31, 2006. Further, if we are unable to successfully complete the conversion to Petrodelta, we believe the Venezuelan government will seize our assets and take over Venezuelan operations. Our recourse will be to pursue claims in arbitration for expropriation of our interests or similar claims against the Venezuelan government. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to outcome.
Certain conditions to signing the Conversion Contract may not be met.Before we sign the Conversion Contract, certain conditions must be satisfied, most of which are beyond our control. These conditions include approval by the Venezuelan Ministry of Energy and Petroleum (“MEP”) and the Venezuelan National Assembly; obtaining or filing all necessary consents, authorizations, orders or approvals of governmental authorities; making all necessary filings or registrations with governmental authorities and giving all requisite notifications to governmental authorities; completion of the Conversion Contract and all annexes, including the11
business plan; and the award of the Isleño, Temblador and El Salto fields to Petrodelta by the Venezuelan government.
Until conversion to Petrodelta is complete, we will likely continue to incur expenses without receiving revenues.Even though it is our position that the OSA is still in place, as a result of actions by the government of Venezuela, Harvest Vinccler currently has no recognized agreement setting out its rights and obligations within Venezuela. Harvest Vinccler continues in the day-to-day operations of the SMU fields and continues to incur expenses in doing so; however, there are no contractual means recognized by Venezuela to receive revenues or be reimbursed for costs and expenses during the period prior to the conversion to Petrodelta. Although the MOU provides that upon completion of the conversion, there will be an adjustment between the parties to obtain the same economic result as if the conversion had
14 employees.Titlebeen completed on April 1, 2006, this adjustment will not occur until and unless the conversion is completed. The timing for completing the conversion to DevelopedPetrodelta is uncertain. While we continue to maintain cash reserves, our operations in Venezuela represent all of our revenues, and Undeveloped Acreage
All Venezuelanthe funds available to pursue our growth strategy may be adversely affected by the financial demands of continued operations in Venezuela during the conversion process.
Until the conversion to Petrodelta is complete and drilling operations resume, our production volumes will continue to decline.Since 2005, our volumes of crude oil and natural gas deliveries have declined significantly. The decline is due to PDVSA’s refusal to allow us to carry out our drilling and facilities program for 2005 and 2006 and the natural decline of the field. Until conversion is completed, the resumption of any significant drilling operations is unlikely and the SMU field’s production volumes will continue to decline.
If the conversion to Petrodelta is completed, we will be a minority interest owner in Petrodelta.Upon conversion of the OSA to Petrodelta and transfer of our assets to Petrodelta, we will be a minority interest owner and no longer have sole control over operations. Our control of Petrodelta will be limited to our rights under the Conversion Contract and its annexes and the Charter and By-Laws of Petrodelta. As a result, our ability to implement our business plan, assure quality control, and set the timing and pace of development may be adversely affected.
If the conversion to Petrodelta is completed, our estimates of reserves aremay not be realized. Ryder Scott Company, L.P. provided an estimate of reserves attributable to HNR Finance’s interest in the properties to be operated by Petrodelta. We cannot predict whether the volumes of reserves will ultimately be recovered, and volumes of reserves actually recovered may differ significantly from estimated quantities.
If the conversion to Petrodelta is completed, our flexibility in selling or exchanging a direct or indirect interest in Petrodelta to diversify our assets and acquire additional properties may be limited.We continue to look at alternatives to diversify our assets. However, the alternatives are limited. If the conversion to Petrodelta is completed, and we decide to enter into a sale or exchange of all or part of our Venezuelan assets with an operating service agreement between Benton-Vinccler and PDVSA, under which all mineral rights are ownedunrelated third party, the third party must be approved by the GovernmentVenezuelan government. The number of potential buyers that will be acceptable to the Venezuelan government may be limited, and this number of potential buyers may be further affected and limited by country risk concerns. Further, a sale or exchange of all or part of our Venezuelan assets after completing the conversion to Petrodelta may be subject to U.S. federal tax consequences.
If the conversion to Petrodelta is completed, CVP and PPSA might not have the funds available to reimburse us for oil and gas deliveries made during the period prior to conversion.Pursuant to the MOU, CVP has agreed to make an economic adjustment to compensate us so as to achieve the same economic result as if the conversion had been completed on April 1, 2006. This adjustment is to occur once the conversion is completed. However, there are no assurances that CVP and PPSA will have adequate funds to make payment to us for the period dating back to April 1, 2006.
The total capital required for development of the fields in Venezuela may exceed the ability of Harvest Vinccler and CVP to finance.Our ability to fully develop the fields in Venezuela will require a significant investment. Our and CVP’s future capital requirements for the development of the SMU fields and the Isleño, Temblador and El Salto fields may exceed the cash available from existing cash flow and cash on hand. Our ability to secure financing is currently limited and uncertain, and has been and may be affected by numerous factors beyond our control, including the risks associated with operating in Venezuela.
Because of this financial risk, we12
may not be able to secure either the equity or debt financing necessary to meet our future cash needs for investment, which may limit our ability to fully develop the properties, cause delays with their development or require early divestment of all or a portion of those projects. Failure by us to meet a capital requirement could be a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited.
The loss of key personnel or the ability to establish and retain an experienced and competent workforce in Venezuela could adversely affect our ability to successfully execute our business plan.Our ability to successfully implement the business plan for Petrodelta depends to a large degree on the skills and experience of individuals in key management and operating positions and retaining a capable workforce. We have no assurances that key employees will remain after the conversion to Petrodelta is completed or that Petrodelta will be able to attract and retain competent employees to replace those employees who do not remain with Petrodelta. Moreover, as a minority interest owner in Petrodelta, we have a limited ability to appoint key positions or control decisions on workforce staffing.
Pending conversion to Petrodelta, the actions of CVP, through its members to the Petrodelta board and its appointed General Manager or President, may adversely affect our ability to conduct operations and retain key personnel.
Contracting policies and procedures of Petrodelta could adversely affect successful execution of the business plan.Successful implementation of the business plan of Petrodelta will require the use of skilled and competitively priced contractors for the development of the fields, including the drilling of wells, building of infrastructure and providing essential services. Due to factors such as global competition and the business climate in Venezuela, contractors, labor, and materials and equipment may not be readily available at competitive prices. Further, as a minority interest owner in Petrodelta, our influence over contracting decisions and contracting policies and procedures is limited.
Petrodelta’s business plan will be sensitive to market prices for oil.Petrodelta will be operating under a business plan, the success of which will rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may not be successful.
A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta.Under the terms of the Conversion Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires that if in any year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the hydrocarbons produced, Petrodelta must pay the government the difference. In the event of a significant decline in crude prices, the ventajas especiales could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying the business plan or restricting the budget is limited under the Conversion Contract.
Oil price declines and volatility could adversely affect Petrodelta’s future, our revenue, cash flows and profitability.Prices for oil fluctuate widely. Prices also affect the amount of cash flow available for capital expenditures and dividends from Petrodelta. Any restrictions on future dividends from Petrodelta may impact our ability to service our Venezuelan debt. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause fluctuations in oil prices include:
| • | | relatively minor changes in the global supply and demand for oil; |
|
| • | | export quotas; |
|
| • | | market uncertainty; |
|
| • | | the level of consumer product demand; |
|
| • | | weather conditions; |
|
| • | | domestic and foreign governmental regulations and policies; |
|
| • | | the price and availability of alternative fuels; |
|
| • | | political and economic conditions in oil-producing and oil consuming countries; and |
|
| • | | overall economic conditions. |
13
If the conversion to Petrodelta is not completed, our ability to pursue other transactions will be limited.If the conversion to Petrodelta is not completed, we will continue to assess and consider other strategic alternatives for preserving value, including a transfer of all or part of our Venezuelan assets to another party, and we will continue to pursue other business opportunities and investments unrelated to Venezuela. There can be no assurance that we will be able to successfully pursue any such strategic alternatives. Without completion of conversion to Petrodelta, the alternatives available to us are more limited and subject to a number of significant variables.
The WAB-21 petroleum contract lies withinlegal or fiscal regime for Petrodelta may change and the Venezuelan government may not honor its commitments.While we believe that the Conversion Contract and Petrodelta provide a basis for a more durable arrangement in Venezuela, the value of the business necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our recent experiences in Venezuela demonstrate that such stability should not be assumed because the Venezuelan government may not honor its legal and contractual commitments. While we have and will continue to take measures to mitigate our risks, no assurance can be provided that we will be successful in doing so or that events beyond our control will not adversely affect the value of our business in Venezuela.
The actions of the Venezuelan government may cause us to file for international arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, we delivered formal notices to Venezuelan government officials of an areainvestment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to its outcome.
Continuing to do business in Venezuela is subject to risk.Our operations in Venezuela are subject to various risks including, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, change in laws, exchange controls, war, insurrection, civil unrest, strikes and other political risks, being subject to foreign laws, legal systems and the exclusive jurisdiction of Venezuelan courts or tribunals, unilateral renegotiation of contracts with the Venezuelan government and changes in laws and policies governing operations of mixed companies. These factors increase our exposure to production disruptions and project execution risk.
Remaining in Venezuela may limit our ability to acquire other oil and gas properties.Under our business plan, Petrodelta may not be a significant source of dividends in its early years. Moreover, our lack of asset diversification and concentration of risk limits our access to both debt and equity capital. Therefore, our near-term growth and diversification must come from unrestricted cash on hand and asset-based lending, rather than cash or debt from our Venezuelan operations. This may limit the size and type of other projects we are able to acquire.
Tax claims by municipalities in Venezuela may adversely affect Harvest Vinccler’s financial condition.The municipalities of Uracoa and Libertador have asserted numerous tax claims against Harvest Vinccler which we believe are without merit. However, the reliability of Venezuela’s judicial system is a source of concern and it can be subject to local and political influences. Accordingly, no assurance can be given that the tax claims will be overturned. Enforcement of the claims through court order requested by the municipalities, even while the claims are under review, could lead to the seizure of Harvest Vinccler’s assets.
Our strategy to focus on Russia and other countries perceived to be politically challenging carries greater deal execution, operating, financial, legal and political risks.While we believe our established presence in countries perceived to be politically challenging and our experience and skills from prior operations position us well for future projects, doing business in Russia and other countries perceived to be politically challenging also carries unique risks. The operating environment is often difficult and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and14
operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have operational and financial control. Recently, the Russian government began to consider legislation to restrict certain “strategic” projects in Russia to majority-owned Russian companies. If adopted, such legislation could adversely affect our ability to acquire projects in Russia consistent with our strategy.
Operations in areas outside the United States are subject to various risks inherent in foreign operations, and our strategy to focus on countries perceived to be politically challenging limits our risk diversification.Our operations 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, including taxes, 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 and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. Our strategy to focus on countries perceived to be politically challenging increases our exposure to operating, financial and political risks.
Our cash position and limited ability to access additional capital may limit our growth opportunities.We have used $88.9 million of our cash as collateral for debt in Venezuela, and, until conversion to Petrodelta, there will be no additional cash available from operations. The unfinished conversion to Petrodelta also significantly limits our access to additional capital, and, after conversion, the concentration of our political risk in Venezuela may limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta, in particular for the period from April 1, 2006 through the date of conversion. While we believe such dividends, if available, will be paid, there is no assurance this will be the case. These factors may limit our ability to grow through the acquisition of additional oil and gas properties and projects.
Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela is considered a highly inflationary economy. There are many factors which affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Bolivar to the U.S. Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates. The majority of our Venezuelan receipts are denominated in U.S. Dollars. A large portion of our operating and capital expenditures are in U.S. Dollars. For a discussion of currency controls in Venezuela, seeItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources.Successful acquisition of projects in any international country may also expose us to foreign currency risk in that country.
Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Annual Report on Form 10-K contains estimates of our proved oil and natural gas 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. Until we complete the conversion to Petrodelta, we will not have reserves to report under SEC guidelines and, accordingly, no reserves are reported as of December 31, 2006. Moreover, our quantities of proved reserves in 2005 were reduced to remove undeveloped reserves because the actions taken by the Venezuelan government created uncertainty as to whether these reserves would be recovered under the economic and operating conditions which existed in Venezuela (“Contractually Restricted Reserves”).
The process of estimating oil and natural gas reserves is complex requiring 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 likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. Actual production, revenue, taxes, development expenditures and15
operating expenses with respect to our reserves will likely vary from the estimates used, and these variances may be material.
You should not assume that the present value of future net revenues referred to inNotes to the Consolidated Financial Statements, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantitiesis 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 natural 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 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 natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. We will not have any reserves to report under SEC guidelines until we complete the conversion to Petrodelta or acquire additional properties 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 often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a territorial dispute betweenvariety of factors, many of which are beyond our control. These factors include:
| • | | unexpected drilling conditions; |
|
| • | | pressure or irregularities in formations; |
|
| • | | equipment failures or accidents; |
|
| • | | weather conditions; |
|
| • | | shortages in experienced labor; |
|
| • | | delays in receiving necessary governmental permits; |
|
| • | | shortages or delays in the delivery of equipment; |
|
| • | | delays in receipt of permits or access to lands; and |
|
| • | | government actions or changes in regulations. |
The prevailing price of oil also affects the People’s Republiccost of China and Vietnam. Vietnam has executed an agreement on athe demand for drilling rigs, production equipment and related services. We cannot assure you 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
same offshore acreagerisk 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 risks16
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 third party. highly competitive environment. We compete with major, national and independent oil and natural gas companies for the acquisition of desirable oil and natural 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 natural 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.
The territorial dispute has existed for many years,loss of key personnel could adversely affect our ability to successfully execute our strategy.We are a small organization and there has been limited explorationdepend on the skills and no development activityexperience of a few individuals in key management and operating positions to execute our business strategy. Loss of one or more key individuals in the area under dispute. It is uncertain whenorganization could hamper or how this dispute will be resolved, and under what terms the various countries and parties to the agreements may participate in the resolution.delay achieving our strategy.
Item 1B. Unresolved Staff Comments
None.
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 lease 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expires in December 2004. We have subleased all of theAlso during 2004, Harvest Vinccler leased office space in CaliforniaMaturin and Caracas, Venezuela for rents that approximateapproximately $13,200 and $4,000 per month, respectively. See alsoItem 1 – Businessfor a description of our lease costs.oil and natural gas properties and reserves.
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, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas.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. TheIn October 2003, 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. We are unable to estimate the amount or range of any possible loss.
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 SMU fields are located. A protest to the assessments was filed with the municipality, and in October 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. In July 2006, the Uracoa Municipality issued two additional assessments seeking to impose an increase in tax rates for the last quarter of 2005 and the first quarter of 2006. In August 2006, the Uracoa Municipality issued two further assessments, including penalties, for second quarter 2006 estimated revenues based on the first quarter 2006 oil and natural gas sales and for supposed errors of Harvest Vinccler as withholding agent. We dispute all of the tax assessments and17
believe we have a substantial basis for our positions. We are unable to estimate the amount or range of a possible loss.
Libertador Municipality Tax Assessment. In April 2005, Harvest Vinccler received a tax assessment from a tax inspector for the Libertador municipality in which part of the SMU fields are located. Harvest Vinccler has submitted a protest to the assessment at the Mayor’s Office, and if no favorable resolution is obtained, it will file a motion with the tax court seeking to enjoin the payment order and dismiss the assessment. We dispute the allegations set forth in the assessment and believe we have a substantial basis for our position. We are unable to estimate the amount or range of a possible loss.
International Arbitration. As a result of the actions taken by PDVSA, the Ministry of Energy and Petroleum (“MEP”) and the SENIAT, in July 2005, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank.
The SENIAT Tax Assessment. In July 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 202 billion Bolivars, or approximately $94 million, related to 2001 through 2004 tax years. We determined not to contest two elements of the claim and made payments totaling 11.3 billion Bolivars, or $5.3 million, in August and September, 2005. During the second quarter 2006, the SENIAT initiated an audit of 2005 tax payments, and in October 2006, Harvest Vinccler received an assessment from the SENIAT for 2005 taxes in the amount of $15.8 million. In 2006, Harvest Vinccler resolved and substantially paid all of the tax claims made by the SENIAT. Harvest Vinccler paid $73.8 million additional taxes and related interest for the periods of 2001 through first quarter 2006.
Item 4. Submission of Matters to a Vote of Security Holders
At a special meeting of stockholders held on December 18, 2006, the following items were voted on by the stockholders:
| 1. | | Proposal to approve the proposed transaction, including the conversion contract between our subsidiary Harvest Vinccler, S.C.A. and Corporación Venezolana del Petroleo, S.A., and entailing the transfer of substantially all of our assets to Empresa Mixta Petrodelta, S.A., pursuant to the conversion contract: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 30,910,607 | | 133,118 | | 114,731 |
| 2. | | Proposal to postpone or adjourn the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the time of the special meeting to approve the transaction described in proposal 1: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 27,746,888 | | 3,282,231 | | 129,337 |
| 3. | | To vote on such other matters as may properly come before the special meeting or any adjournment or postponement of the special meeting: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 18,457,926 | | 10,894,377 | | 1,806,153 |
None.
1418
PART IIRisk Factors
We face significant risks in Venezuela. These risks and other risk factors are discussed inItem 5. Market1A – Risk FactorsandItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of 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
Registrant’s Common Equitythe 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
Related Stockholder MattersPRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our Common Stocklies within an area which is tradedthe subject of a border 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 border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute.
Location and Geology
The WAB-21 contract area is located in the West Wan’an Basin (Nam Con Son) on the New York Stock Exchange (“NYSE”) underSouth China Sea. Its western edge lies approximately 50 miles southeast of the symbol “HNR”.Dai Hung (Big Bear) Oil Field. The block is to the east of significant natural gas discoveries at Lan Tay and Lan Do, which are reported to contain two trillion cubic feet of natural gas. WAB-21 is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas and east of the Dua and Blackbird discoveries that successfully tested oil and gas in 2006. The WAB-21 contract area covers several similar structural trends and geological formations, each with potential for hydrocarbon reserves in possible multiple pay zones similar to the known fields and discoveries.
Drilling and Development Activity
Due to the border dispute between China and Vietnam, we have been unable to pursue an exploration program during phase one of the contract. As of Decembera result, we have obtained license extensions, with the current extension in effect until May 31, 2003, there were 35,674,660 shares of common stock outstanding, with approximately 808 stockholders of record.2007. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.
Activities by Area
The following table
sets forth the high and low sales prices forsummarizes our
Common Stock reportedconsolidated activities by
the NYSE.| | | | | | | | | | | |
Year
| | Quarter
| | High
| | Low
|
2002 | | | | | | | | | | |
| | | First quarter | | | 4.03 | | | | 1.43 | |
| | | Second quarter | | | 5.00 | | | | 3.77 | |
| | | Third quarter | | | 5.43 | | | | 3.21 | |
| | | Fourth quarter | | | 7.54 | | | | 5.50 | |
2003 | | | | | | | | | | |
| | | First quarter | | | 6.58 | | | | 4.40 | |
| | | Second quarter | | | 6.90 | | | | 4.20 | |
| | | Third quarter | | | 7.17 | | | | 5.58 | |
| | | Fourth quarter | | | 10.02 | | | | 6.35 | |
On March 1, 2004, the last sales price for the common stock as reported by the NYSE was $11.68 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.
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. 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 1999 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2002, 2001, 2000 and 1999, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001, 2000 and 1999.
158
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31,
|
| | | 2003
| | 2002
| | 2001
| | 2000
| | 1999
|
| | | (in thousands, except per share data) |
Statement of Operations: | | | | | | | | | | | | | | | | | | | | |
| Total revenues | | $ | 106,095 | | | $ | 126,731 | | | $ | 122,386 | | | $ | 140,284 | | | $ | 89,060 | |
| Operating income (loss) | | | 33,627 | | | | 34,585 | | | | 28,201 | | | | 53,204 | | | | (22,525 | ) |
| Net income (loss) | | | 27,303 | | | | 100,362 | | | | 43,237 | | | | 20,488 | | | | (32,284 | ) |
| Net income (loss) per common share: | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.77 | | | $ | 2.90 | | | $ | 1.27 | | | $ | 0.67 | | | $ | (1.09 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Diluted | | $ | 0.74 | | | $ | 2.78 | | | $ | 1.27 | | | $ | 0.66 | | | $ | (1.09 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Weighted average common shares outstanding Basic | | | 35,332 | | | | 34,637 | | | | 33,937 | | | | 30,724 | | | | 29,577 | |
| Diluted | | | 36,840 | | | | 36,130 | | | | 34,008 | | | | 30,890 | | | | 29,577 | |
| | | | | | | | | | | | | |
| (in thousands) | | Venezuela | | United States | | Total |
Year ended December 31, 2006 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 59,506 | | | | — | | | $ | 59,506 | |
| Total Assets | | $ | 306,289 | | | $ | 116,422 | | | $ | 422,711 | |
| | | | | | | | | | | | | |
Year ended December 31, 2005 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 236,941 | | | | — | | | $ | 236,941 | |
| Total Assets | | $ | 258,268 | | | $ | 142,530 | | | $ | 400,798 | |
| | | | | | | | | | | | | |
Year ended December 31, 2004 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 186,066 | | | | — | | | $ | 186,066 | |
| Total Assets | | $ | 309,794 | | | $ | 57,692 | | | $ | 367,486 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31,
|
| | | 2003
| | 2002
| | 2001
| | 2000
| | 1999
|
| | | | | | | | | | | (in thousands) | | | | | | | | |
Balance Sheet Data: | | | | | | | | | | | | | | | | | | | | |
| Working capital (deficit) | | $ | 137,210 | | | $ | 97,001 | | | $ | (586 | ) | | $ | 12,370 | | | $ | 32,093 | |
| Total assets | | | 374,348 | | | | 335,192 | | | | 348,151 | | | | 286,447 | | | | 276,311 | |
| Long-term debt, net of current maturities | | | 96,833 | | | | 104,700 | | | | 221,583 | | | | 213,000 | | | | 264,575 | |
Stockholders’ equity (deficit)(1) | | | 199,713 | | | | 171,317 | | | | 67,623 | | | | 12,904 | | | | (17,178 | ) |
In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the period ended March 31, 2006, and years ended December 31, 2005 and 2004. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest.
| | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2006(a) | | 2005 | | 2004 |
Venezuela(b) | | | | | | | | | | | | |
| Crude Oil Production (Bbls) | | | 1,894,101 | | | | 8,762,687 | | | | 8,152,261 | |
| Natural Gas Production (Mcf) | | | 4,506,094 | | | | 25,677,460 | | | | 31,059,416 | |
Average Crude Oil Sales Price ($per Bbl)(c) | | $ | 28.96 | | | $ | 24.02 | | | $ | 18.90 | |
| Average Natural Gas Sales Price ($per Mcf) | | $ | 1.03 | | | $ | 1.03 | | | $ | 1.03 | |
| Average Operating Expenses ($per Boe) | | $ | 3.49 | | | $ | 3.05 | | | $ | 2.50 | |
| | |
| (a) | | Reflects oil and natural gas deliveries through March 31, 2006. |
|
| (b) | | Information represents 100 percent of production. |
|
| (c) | | Average crude oil sales price after hedging activity. |
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; |
|
| • | | tax, environmental, safety and other laws relating to the petroleum industry; |
|
| • | | changes in laws relating to the petroleum industry; |
|
| • | | changes in administrative regulations and the interpretation and application of such rules and regulations; 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, sometimes retroactively, for a variety of political, economic, environmental and9
other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and our potential for economic loss.
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 Bolivar and the U.S. Dollar and restrict the ability to exchange Bolivars for U.S. Dollars and vice versa. The Bolivar is not readily convertible into the U.S. Dollar. We do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the foreseeable future.
No capital expenditures to comply with environmental regulations were required in 2004, 2005 or 2006. Harvest 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) $1.5 million, $9.0 million and $39.2 million in 2006, 2005 and 2004, respectively. Included in these numbers is $8.9 million and $33.5 million for the development of proved undeveloped reserves in 2005 and 2004, respectively.
We have participated in the drilling of wells as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2006 | | 2005 | | 2004 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Wells Drilled: | | | | | | | | | | | | | | | | | | | | | | | | |
| Development: | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | | — | | | | — | | | | 1 | | | | 0.8 | | | | 16 | | | | 12.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Average Depth of Wells (Feet) | | | — | | | | — | | | | — | | | | 4,349 | | | | — | | | | 5,443 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Producing Wells(1): | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude Oil | | | 103 | | | | 82.4 | | | | 108 | | | | 86.4 | | | | 124 | | | | 99.2 | |
| | |
| (1) | | No cash dividends were declared or paid during the periods presented.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 were conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.
Acreage
The following table summarizes the undeveloped acreage that we hold under concession as of December 31, 2006:
| | | | | | | | | |
| | | Undeveloped |
| | | Gross | | Net |
| China | | | 7,470,080 | | | | 7,470,080 | |
| | | | | | | | | |
10
Title to Undeveloped Acreage
The WAB-21 petroleum contract lies within an area which is the subject of a border dispute between China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with a third party. The border dispute has existed for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the 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.
Competition
We encounter substantial competition from major, national and independent oil and natural gas companies 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 natural gas properties include staff and data necessary to identify, investigate and purchase such properties, the financial resources necessary to acquire and develop such 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, results of operations and cash flows.
Employees
At December 31, 2006, our Houston office had 18 full-time employees. Harvest Vinccler had 240 employees and our Moscow and London offices had 11 and 5 employees, respectively. We augment our staffs from time to time with independent consultants, as required.
| |
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
In addition to the other information set forth elsewhere in this Form 10-K, the following factors should be carefully considered when evaluating us. Our concentrationWhile approved by our stockholders, the conversion of assetsthe OSA to Petrodelta may not be completed and we may not recover our investments or be compensated for our services in Venezuela, increasesand our exposure to production disruptions and project execution risk.Political and economic uncertainty is very high in Venezuela. Currently, the production from the South Monagas Unitinterests in Venezuela
representsmay be unlawfully confiscated by the Venezuelan government.Since April 1, 2006, our operations in Venezuela have continued to be conducted pursuant to the terms of the OSA, which the government no longer recognizes and which it claims is illegal. As such, our future ability to contractually recover all
or part of our
production,investments and
revenue and cash flow will be
adversely affected if production fromcompensated for our services depends on completing the
South Monagas Unit decreases significantlyprocess for
any reason. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA’s inability to accept our oil due to the
national civil work stoppage in Venezuela. As a result, 2002 sales were reduced by approximately 0.6 million barrels and 2003 sales were reduced by an estimated 1.2 million barrels. As a resultconversion of the
Venezuelan national civil work stoppage,OSA and transfer of our interests to Petrodelta. If we are unable to convert to Petrodelta, we may not be paid for oil and natural gas produced after March 31, 2006. Further, if we are unable to successfully complete the conversion to Petrodelta, we believe the Venezuelan government
terminated several thousand PDVSA employeeswill seize our assets and
announced a restructuringtake over Venezuelan operations. Our recourse will be to pursue claims in arbitration for expropriation of
PDVSA’s operations. Throughout 2003, there have been numerous organizational changes in PDVSA. As a result ofour interests or similar claims against the
situation in PDVSA, its payment to Benton-Vinccler for crude oil delivered in the fourth quarter of 2002 was late by seven days. However, all other payments have been on time, and we believe PDVSA is committed to building its production levels and returning to more normalized business relations with its customers and suppliers. There are ongoing efforts by opponents of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of the changes and the possible politicalization of PDVSA cannot be predicted, it could adversely affect PDVSA’s ability to manage its contracts and meet its obligations with its suppliers and vendors, such as Benton-Vinccler. Organizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing of those acquisitions. While we have substantial cash reserves to withstand a future
16
disruption of sales, a prolonged loss of sales or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition.
We have been required to curtail sales to PDVSA in April and December 2002 due to insufficient crude oil storage capacity. While these appear to be isolated incidents, we cannot be assured that our sales to PDVSA will not be curtailed in the future in the same manner.
Our strategy to focus on Russia carries operating, financial, legal and political risk.While we believe our established presence in Russia and our experience and skills from prior operations positions us well for future projects, doing business in Russia also carries unique risks. The operating environment is often difficult, and the ability to operate successfully will depend onVenezuelan government. An arbitration proceeding may take a number of factors, including our abilityyears to controlconclude and we can provide no assurances as to outcome.
Certain conditions to signing the pace of development, apply “best practices” in drilling and development, andConversion Contract may not be met.Before we sign the
fostering of relationships with Russian partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for Russian projects, while remaining within our existing debt covenants. In addition, the Russian legal system is not mature and its reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and gas projects, as well as our ability to obtain adequate compensation for any resulting losses.Acquiring new projects in Venezuela depends upon our ability to meet the requirements of the Organic Hydrocarbon Law.New oil projects in Venezuela are governed by the Organic Hydrocarbon Law which requires that such projectsConversion Contract, certain conditions must be carried out through incorporated joint ventures with majority ownership by governmental entities. While we believe it is possible to comply with the Organic Hydrocarbons Law and at the same time meet our criteria for new projects, no precedents exist and there is a risk we will be unable to achieve the desired result.
Operations in areas outside the U.S. are subject to various risks inherent in foreign operations, and our strategy to focus on Venezuela and Russia limits our country risk diversification.Our operations in areas outside the U.S. are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and the possibility of having to be subject to exclusive jurisdiction of courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. Our strategy to focus on Venezuela and Russia concentrates our foreign operations risk and increases the potential impact to us of the operating, financial and political risks in those countries.
Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela has historically been considered a highly inflationary economy. Results of operations in that country are measured in U.S. dollars, and 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, manysatisfied, most of which are beyond our influence. We havecontrol. These conditions include approval by the Venezuelan Ministry of Energy and Petroleum (“MEP”) and the Venezuelan National Assembly; obtaining or filing all necessary consents, authorizations, orders or approvals of governmental authorities; making all necessary filings or registrations with governmental authorities and giving all requisite notifications to governmental authorities; completion of the Conversion Contract and all annexes, including the11
business plan; and the award of the Isleño, Temblador and El Salto fields to Petrodelta by the Venezuelan government.
Until conversion to Petrodelta is complete, we will likely continue to incur expenses without receiving revenues.Even though it is our position that the OSA is still in place, as a result of actions by the government of Venezuela, Harvest Vinccler currently has no recognized significant exchange gainsagreement setting out its rights and lossesobligations within Venezuela. Harvest Vinccler continues in the past, resulting from fluctuations in the relationshipday-to-day operations of the Venezuelan currencySMU fields and continues to incur expenses in doing so; however, there are no contractual means recognized by Venezuela to receive revenues or be reimbursed for costs and expenses during the period prior to the U.S. dollar. Itconversion to Petrodelta. Although the MOU provides that upon completion of the conversion, there will be an adjustment between the parties to obtain the same economic result as if the conversion had been completed on April 1, 2006, this adjustment will not occur until and unless the conversion is not possiblecompleted. The timing for completing the conversion to predictPetrodelta is uncertain. While we continue to maintain cash reserves, our operations in Venezuela represent all of our revenues, and the extentfunds available to which wepursue our growth strategy may be adversely affected by future changes in exchange rates. Our Venezuelan receipts are denominated in U.S. dollars, and most expenditures are in U.S. dollars as well. For a discussionthe financial demands of currency controlscontinued operations in Venezuela seeCapital Resourcesduring the conversion process.
Until the conversion to Petrodelta is complete and Liquiditybelow. Successful acquisitiondrilling operations resume, our production volumes will continue to decline.Since 2005, our volumes of projects in Russia may also exposecrude oil and natural gas deliveries have declined significantly. The decline is due to PDVSA’s refusal to allow us to foreign currency riskcarry out our drilling and facilities program for 2005 and 2006 and the natural decline of the field. Until conversion is completed, the resumption of any significant drilling operations is unlikely and the SMU field’s production volumes will continue to decline.
If the conversion to Petrodelta is completed, we will be a minority interest owner in that country.The lossPetrodelta.Upon conversion of key personnel could adversely affectthe OSA to Petrodelta and transfer of our assets to Petrodelta, we will be a minority interest owner and no longer have sole control over operations. Our control of Petrodelta will be limited to our rights under the Conversion Contract and its annexes and the Charter and By-Laws of Petrodelta. As a result, 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 executeimplement our business strategy. Lossplan, assure quality control, and set the timing and pace of one or more key individualsdevelopment may be adversely affected.
If the conversion to Petrodelta is completed, our estimates of reserves may not be realized. Ryder Scott Company, L.P. provided an estimate of reserves attributable to HNR Finance’s interest in the organization could hamperproperties to be operated by Petrodelta. We cannot predict whether the volumes of reserves will ultimately be recovered, and volumes of reserves actually recovered may differ significantly from estimated quantities.
If the conversion to Petrodelta is completed, our flexibility in selling or delay achievingexchanging a direct or indirect interest in Petrodelta to diversify our strategy.Leverage materially affectsassets and acquire additional properties may be limited.We continue to look at alternatives to diversify our operations. Asassets. However, the alternatives are limited. If the conversion to Petrodelta is completed, and we decide to enter into a sale or exchange of December 31, 2003, our long-term debt was $96.8 million. Our long-term debt represented 33 percentall or part of our total capitalization at December 31, 2003. Our current
17
cash balances are in excessVenezuelan assets with an unrelated third party, the third party must be approved by the Venezuelan government. The number of these obligationspotential buyers that will be acceptable to the Venezuelan government may be limited, and lessen the impactthis number of potential buyers may be further affected and limited by country risk concerns. Further, a sale or exchange of all or part of our debt but our long-term debt can effect our operations in several important ways, includingVenezuelan assets after completing the following:
| • | | a significant portion of our cash flow from operations is used to pay interest on borrowings; |
|
| • | | our single largest indebtedness of $85 million is due in November 2007; |
|
| • | | the covenants contained in the indentures governing such debt limits our ability to borrow additional funds or to dispose of assets; |
|
| • | | the covenants contained in the indentures governing our debt affect our flexibility in planning for, and reacting to, changes in business conditions; |
|
| • | | the level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and |
|
| • | | the terms of the indentures governing our debt permit our creditors to accelerate payments upon an event of default or a change of control. |
conversion to Petrodelta may be subject to U.S. federal tax consequences.
If the conversion to Petrodelta is completed, CVP and PPSA might not have the funds available to reimburse us for oil and gas deliveries made during the period prior to conversion.Pursuant to the MOU, CVP has agreed to make an economic adjustment to compensate us so as to achieve the same economic result as if the conversion had been completed on April 1, 2006. This adjustment is to occur once the conversion is completed. However, there are no assurances that CVP and PPSA will have adequate funds to make payment to us for the period dating back to April 1, 2006.
The total capital required for development of newthe fields in Venezuela may exceed ourthe ability of Harvest Vinccler and CVP to finance.Our ability to
finance.fully develop the fields in Venezuela will require a significant investment. Our
and CVP’s future capital requirements for
new projectsthe development of the SMU fields and the Isleño, Temblador and El Salto fields may exceed the cash available from existing
free cash flow and cash on hand. Our ability to
acquiresecure financing is
currently limited and uncertain,
and has been and may be affected by numerous factors beyond our
control.control, including the risks associated with operating in Venezuela. Because of
thethis financial risk,
factors in the countries in which we
operate, we 12
may not be able to secure either the equity or debt financing necessary to meet
anyour future cash needs for investment, which may limit our ability to fully develop
new projects,the properties, cause delays with their development or require early divestment of all or a portion of those projects.
Failure by us to meet a capital requirement could be a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited.
The loss of key personnel or the ability to establish and retain an experienced and competent workforce in Venezuela could adversely affect our ability to successfully execute our business plan.Our currentability to successfully implement the business plan for Petrodelta depends to a large degree on the skills and future revenueexperience of individuals in key management and operating positions and retaining a capable workforce. We have no assurances that key employees will remain after the conversion to Petrodelta is completed or that Petrodelta will be able to attract and retain competent employees to replace those employees who do not remain with Petrodelta. Moreover, as a minority interest owner in Petrodelta, we have a limited ability to appoint key positions or control decisions on workforce staffing.
Pending conversion to Petrodelta, the actions of CVP, through its members to the Petrodelta board and its appointed General Manager or President, may adversely affect our ability to conduct operations and retain key personnel.
Contracting policies and procedures of Petrodelta could adversely affect successful execution of the business plan.Successful implementation of the business plan of Petrodelta will require the use of skilled and competitively priced contractors for the development of the fields, including the drilling of wells, building of infrastructure and providing essential services. Due to factors such as global competition and the business climate in Venezuela, contractors, labor, and materials and equipment may not be readily available at competitive prices. Further, as a minority interest owner in Petrodelta, our influence over contracting decisions and contracting policies and procedures is limited.
Petrodelta’s business plan will be sensitive to market prices for oil.Petrodelta will be operating under a business plan, the success of which will rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may not be successful.
A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta.Under the terms of the Conversion Contract and other governmental documents, Petrodelta is subject to
concentrated counter-party risk.Our current operationsa special advantage tax (“ventajas especiales”) which requires that if in
Venezuela rely on production fee payments from PDVSA for all revenue receipts. We do not ownany year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the hydrocarbons
and do not sell oil and gasproduced, Petrodelta must pay the government the difference. In the event of a significant decline in
open markets. Future projects in Venezuela, Russia and other countries may involve similar production fee payments fromcrude prices, the ventajas especiales could force Petrodelta to operate at a
loss. Moreover, our ability to control those losses by modifying the business plan or restricting the budget is limited
number of companies or governments.We may not be able to investunder the net cash proceeds from the sale of Geoilbent in new oil and gas projects. The terms of the 2007 Notes require that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the sale, or any amount not so invested must be used to repay or prepay the 2007 Notes or certain debts of subsidiaries.
Conversion Contract.
Oil price declines and volatility could adversely affect Petrodelta’s future, our revenue, cash flows and profitabilityprofitability.. Prices for oil fluctuate widely.
The average price we received for oil in Venezuela increased to $14.07 per Bbl for the year ended December 31, 2003, compared to $13.08 per Bbl for the year ended December 31, 2002. In November 2003, we began selling natural gas in Venezuela under an addendum to our operating service contract at $1.03 per Mcf and Incremental Crude Oil at $7.00 per Bbl. While this diversifies our revenue stream, revenues, profitability and future rate of growth depend substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and
dividends from Petrodelta. Any restrictions on future dividends from Petrodelta may impact our ability to service our
Venezuelan debt.
In addition, we may have ceiling test write-downs when prices decline. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause
this fluctuationfluctuations in oil prices include:
| | • | | relatively minor changes in the global supply of and demand for oil; |
|
| • | | export quotas; |
| |
| | • | | market uncertainty; |
| |
| | • | | the level of consumer product demand; |
| |
| | • | | weather conditions; |
| |
| | • | | domestic and foreign governmental regulations;regulations and policies; |
| |
| | • | | the price and availability of alternative fuels; |
| |
| | • | | political and economic conditions in oil-producing and oil consuming countries; and |
| |
| | • | | overall economic conditions. |
13
LowerIf the conversion to Petrodelta is not completed, our ability to pursue other transactions will be limited.If the conversion to Petrodelta is not completed, we will continue to assess and consider other strategic alternatives for preserving value, including a transfer of all or part of our Venezuelan assets to another party, and we will continue to pursue other business opportunities and investments unrelated to Venezuela. There can be no assurance that we will be able to successfully pursue any such strategic alternatives. Without completion of conversion to Petrodelta, the alternatives available to us are more limited and subject to a number of significant variables.
The legal or fiscal regime for Petrodelta may change and the Venezuelan government may not honor its commitments.While we believe that the Conversion Contract and Petrodelta provide a basis for a more durable arrangement in Venezuela, the value of the business necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our recent experiences in Venezuela demonstrate that such stability should not be assumed because the Venezuelan government may not honor its legal and contractual commitments. While we have and will continue to take measures to mitigate our risks, no assurance can be provided that we will be successful in doing so or that events beyond our control will not adversely affect the value of our business in Venezuela.
The actions of the Venezuelan government may cause us to file for international arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to its outcome.
Continuing to do business in Venezuela is subject to risk.Our operations in Venezuela are subject to various risks including, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, change in laws, exchange controls, war, insurrection, civil unrest, strikes and other political risks, being subject to foreign laws, legal systems and the exclusive jurisdiction of Venezuelan courts or tribunals, unilateral renegotiation of contracts with the Venezuelan government and changes in laws and policies governing operations of mixed companies. These factors increase our exposure to production disruptions and project execution risk.
Remaining in Venezuela may limit our ability to acquire other oil and gas properties.Under our business plan, Petrodelta may not be a significant source of dividends in its early years. Moreover, our lack of asset diversification and concentration of risk limits our access to both debt and equity capital. Therefore, our near-term growth and diversification must come from unrestricted cash on hand and asset-based lending, rather than cash or debt from our Venezuelan operations. This may limit the size and type of other projects we are able to acquire.
Tax claims by municipalities in Venezuela may adversely affect Harvest Vinccler’s financial condition.The municipalities of Uracoa and Libertador have asserted numerous tax claims against Harvest Vinccler which we believe are without merit. However, the reliability of Venezuela’s judicial system is a source of concern and it can be subject to local and political influences. Accordingly, no assurance can be given that the tax claims will be overturned. Enforcement of the claims through court order requested by the municipalities, even while the claims are under review, could lead to the seizure of Harvest Vinccler’s assets.
Our strategy to focus on Russia and other countries perceived to be politically challenging carries greater deal execution, operating, financial, legal and political risks.While we believe our established presence in countries perceived to be politically challenging and our experience and skills from prior operations position us well for future projects, doing business in Russia and other countries perceived to be politically challenging also carries unique risks. The operating environment is often difficult and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and14
operate oil and natural gas prices or downward adjustmentsprojects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our reserves may cause usability to record ceiling limitation write-downs. We usehave operational and financial control. Recently, the full cost method of accountingRussian government began to reportconsider legislation to restrict certain “strategic” projects in Russia to majority-owned Russian companies. If adopted, such legislation could adversely affect our oil and natural gas operations. Accordingly, we capitalize the costability to acquire exploreprojects in Russia consistent with our strategy.
Operations in areas outside the United States are subject to various risks inherent in foreign operations, and our strategy to focus on countries perceived to be politically challenging limits our risk diversification.Our operations 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, including taxes, 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 and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. Our strategy to focus on countries perceived to be politically challenging increases our exposure to operating, financial and political risks.
Our cash position and limited ability to access additional capital may limit our growth opportunities.We have used $88.9 million of our cash as collateral for debt in Venezuela, and, develop oiluntil conversion to Petrodelta, there will be no additional cash available from operations. The unfinished conversion to Petrodelta also significantly limits our access to additional capital, and, gas properties. Under full cost accounting rules,after conversion, the net capitalized costsconcentration of our political risk in Venezuela may limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta, in particular for the period from April 1, 2006 through the date of conversion. While we believe such dividends, if available, will be paid, there is no assurance this will be the case. These factors may limit our ability to grow through the acquisition of additional oil and gas properties may not exceedand projects.
Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela is considered a
“ceiling limit”highly inflationary economy. There are many factors which
is based uponaffect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the
present value of estimated future net cash flowspast, resulting from
proved reserves, discounted at 10 percent,18
plusfluctuations in the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amountrelationship of the excessBolivar to earnings. Thisthe U.S. Dollar. It is called a “ceiling limitation write-down”. This charge does not impact cash flow from operating activities, but does reduce stockholders’ equity.possible to predict the extent to which we may be affected by future changes in exchange rates. The risk that we will be required to write down the carrying valuemajority of our oilVenezuelan receipts are denominated in U.S. Dollars. A large portion of our operating and gas properties increases when oilcapital expenditures are in U.S. Dollars. For a discussion of currency controls in Venezuela, seeItem 7 – Management’s Discussion and natural gas prices are low or volatile. In addition, write-downsAnalysis of Financial Condition and Results of Operations – Capital Resources.Successful acquisition of projects in any international country may occur if we experience substantial downward adjustmentsalso expose us to our estimated proved reserves. The consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downsforeign currency risk in 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.
that country.
Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This
Annual Report on 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.
Until we complete the conversion to Petrodelta, we will not have reserves to report under SEC guidelines and, accordingly, no reserves are reported as of December 31, 2006. Moreover, our quantities of proved reserves in 2005 were reduced to remove undeveloped reserves because the actions taken by the Venezuelan government created uncertainty as to whether these reserves would be recovered under the economic and operating conditions which existed in Venezuela (“Contractually Restricted Reserves”).
The process of estimating oil and natural gas reserves is
complex. Such process requirescomplex requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves
most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth.
In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Actual production, revenue, taxes, development expenditures and
15
operating expenses with respect to our reserves will likely vary from the estimates
used. Suchused, and these variances may be material.
At December 31, 2003, approximately 47 percent of our estimated Proved Reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The estimates of our future reserves include the assumption that we will make significant capital expenditures to develop these reserves. Although we have prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. SeeSupplemental Information on Oil and Natural Gas Producing Activities.
You should not assume that the present value of future net revenues referred to
inNotes to the Consolidated Financial Statements, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantitiesis 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
natural 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
natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics.
OurWe will not have any reserves
into report under SEC guidelines until we complete the
South Monagas Unit in Venezuela will decline as they are produced unless weconversion to Petrodelta or 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.
19
Our operations are subject to numerous risks of oil and natural gas drilling and production activities.Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
| | • | | unexpected drilling conditions; |
| |
| | • | | pressure or irregularities in formations; |
| |
| | • | | equipment failures or accidents; |
| |
| | • | | weather conditions; |
| |
| | • | | shortages in experienced labor; |
| |
| | • | | delays in receiving necessary governmental permits; |
|
| • | | shortages or delays in the delivery of equipment; and |
| |
| | • | | delays in receipt of permits or access to lands.lands; and |
|
| • | | government actions or changes in regulations. |
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
16
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,
national and independent oil and natural gas companies for the acquisition of desirable oil and
natural 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
natural 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.
2003 Financial and Operational Performance
In 2003, we strengthened our management team and board of directors, added to our financial flexibility by completing the sale of Geoilbent for $69.5 million in cash plus $5.5 million for repayment of our intercompany debt and accounts receivable, added a gas revenue stream and advanced our growth plan by announcing an agreement with PDVSA to study two oil and gas fields close to our facilities in Venezuela.
At December 31, 2003, we had $138.7 million of cash and a debt to total capitalization ratio of 33 percent compared with 38 percent at the end of 2002.
20
Our board of directors has authorized the repurchase of up to one million shares of our common stock. In March 2003 we repurchased approximately 80,000 shares for an aggregate price of $0.4 million.
2004 Capital Program
Benton-Vinccler’s capital expenditures for 2004 are projected to be $30-35 million, compared with 2003 capital expenditures of $58.1 million.
The 2004 capital program includes plans for ten wells in Proved Undeveloped Reserves and related facilities at Uracoa for approximately $18 million as well as the start of the engineering and design studies at East Bombal in anticipation of gas sales in 2005. In 2003, we completed our three well Bombal Field development program in Venezuela and constructed a pipeline from Bombal to the Tucupita delivery line. The Bombal drilling program delivered disappointing results. Instead of initial flush production with little or no water, the wells experienced early water breakthrough and consequently lower oil production. Benton-Vinccler converted two gas injection wells in Uracoa to gas production and completed the gas project and facilities improvements on time at a cost of $27 million.
Results of Operations
We include the results of operations of Benton-Vinccler in our consolidated financial statements and reflect the 20 percent ownership interest of Vinccler as a minority interest. We accounted for our investments in Geoilbent and Arctic Gas using the equity method. We include Geoilbent and Arctic Gas in our consolidated financial statements based on a fiscal year ending September 30. Our results of operations for the years ended December 31, 2003, 2002 and 2001 reflect the results of Geoilbent (until sold on September 25, 2003) and Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2003, 2002 and 2001.
You should read the following discussion of the results of operations for each of the years in the three-year period ended December 31, 2003 and the financial condition as of December 31, 2003 and 2002 in conjunction with our Consolidated Financial Statements and related Notes thereto.
We have presented selected expense items from our consolidated income statement as a percentage of revenue in the following table:
| | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | |
|
| | | 2003 | | 2002 | | 2001 |
| | |
| |
| |
|
| Operating Expenses | | | 29 | % | | | 27 | % | | | 35 | % |
| Depletion, Depreciation and Amortization | | | 20 | | | | 21 | | | | 21 | |
| General and Administrative | | | 15 | | | | 13 | | | | 16 | |
| Taxes Other Than on Income | | | 3 | | | | 3 | | | | 4 | |
| Interest | | | 10 | | | | 13 | | | | 20 | |
Years ended December 31, 2003 and 2002
Net income for the year ended 2003 was $27.3 million, or $0.74 per diluted share, compared with $100.4 million for the year ended 2002. The $27.3 million net income included the gain from the sale of our minority equity investment in Geoilbent of $46.6 million, $0.4 million partial recovery of a bad debt and $1.5 million arbitration settlement related to A. E. Benton (SeeNote 13 – Related Party Transactions). Operating and general and administrative expenses were reduced by $3.8 million, or almost 8 percent, compared with 2002.
Our results of operations for the year 2003 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted for all of our production and oil and gas sales revenue. Oil revenue per barrel increased 8 percent (from $13.05 in 2002 to $14.07 in 2003) and oil sales quantities decreased 24 percent (from 9.7 MBbl of oil in 2002 to 7.3 MBbl of oil in 2003) during the year ended 2003 compared with 2002. Gas sales began on November 25, 2003, at the contract rate of $1.03 per Mcf. Incremental Crude Oil sales began on the same date at a fixed price of $7.00 per barrel. Total gas sales were 2.7 Bcf for the period.
Our revenues decreased $20.6 million, or 16 percent, during the year ended 2003 compared with 2002. This was primarily due to lower production offset by higher world crude oil prices. Our sales quantities for the year ended
21
2003 from Venezuela were 7.8 MBoe compared with 9.7 MBoe in 2002. The decrease in sales quantities of 1.9 MBoe, or 20 percent, was due to the Venezuelan national civil work stoppage which led to the shut-in of our production from December 2002 to February 2003, natural reservoir decline rates and the fact that some wells did not immediately return to previous production levels following the national work stoppage.
Our operating expenses decreased $3.1 million, or 9 percent, for the year ended 2003 compared with 2002. This was primarily due to lower production volumes partially offset by higher workover and maintenance programs that continued during the Venezuelan national civil work stoppage. Depletion, depreciation and amortization decreased $5.2 million, or 20 percent, during the year 2003 compared with 2002 primarily due to decreased production from Venezuela and the addition of natural gas reserves in 2002. Depletion expense per barrel of oil produced from Venezuela during 2003 was $2.52 compared with $2.56 during 2002 primarily due to reduced future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during the year ended 2003 compared with $13.4 million for the impairment of the China WAB-21 block and $1.1 million for the Lakeside Prospect exploration activities during the year ended 2002. General and administrative expenses decreased $0.8 million from 2002 to 2003. An arbitration settlement of $1.5 million and a bad debt recovery of $0.4 million were recorded in the third quarter of 2003, and a bad debt recovery of $3.3 million was recorded in the third quarter of 2002 related to A. E. Benton.
Taxes other than on income decreased $0.7 million, or 17 percent, during the year ended 2003 compared with 2002. This was primarily due to decreased Venezuelan municipal taxes which are a function of oil revenues partially offset by a one-time adjustment of U.S. employment taxes of $0.7 million in 2002.
Investment income and other decreased $0.7 million, or 32 percent, during the year ended 2003 compared with 2002. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $5.9 million, or 36 percent, during the year ended 2003 compared with 2002 due to lower average outstanding debt balances for the year ended 2003 compared to 2002. In 2002, we redeemed all $108 million of our 11.625 percent Senior Notes due in May 2003 and purchased $20 million face of the 9.375 percent Senior Notes due in November 2007. In October 2002, we borrowed $15.5 million to finance the construction of the gas pipeline in Venezuela from the Uracoa field to the PDVSA sales line, and we repaid all Bolivar denominated debt in March 2003.
Net gain on exchange rates decreased $4.0 million, or 88 percent, for the year ended 2003 compared with 2002. This was due to the significant devaluation of the Bolivar and Bolivar currency controls imposed in February 2003 which fixed the exchange rate between the Bolivar and the U.S. dollar and restricts the ability to exchange Venezuelan Bolivars for dollars and vice versa. We realized income before income taxes and minority interest of $71.8 million during the year 2003 compared with income of $169.8 million in the year ended 2002. The decrease was primarily attributable to the Arctic Gas Sale in 2002 offset by the sale of our minority equity investment in Geoilbent in 2003. Income tax expense decreased $50.6 million due to lower pre-tax income. The effective tax rate decreased from 36 to 13 percent for the year ended 2003 compared with 2002. The rate decrease was due to an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the benefit was fully reserved in historical periods. The income before minority interests decreased $47.4 million for the year ended 2003 compared with 2002. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by decreased production of Benton-Vinccler.
Equity in net losses of affiliated companies decreased $29.0 million during the year 2003 from $0.2 million in 2002 to a loss of $28.9 million in 2003. This was primarily due to full cost ceiling test writedowns of $32.3 million (our share) and decreased income from Geoilbent. SeeNote 9 – Russian Operations. The year ended 2002 included a loss of $1.5 million on Arctic Gas.
Years ended December 31, 2002 and 2001
Net income for the year ended 2002 was $100.4 million, or $2.78 per diluted share, compared with $43.2 million for 2001. The $100.4 million net income included the after-tax gain from the Arctic Gas Sale of $93.6 million, and the pre-tax $3.3 million, partial recovery of a bad debt related to A. E. Benton (SeeNote 13 – Related Party Transactions); offset, in part, by a pre-tax $13.4 million impairment of the WAB-21 petroleum property located in the South China Sea. Operating and general and administrative expenses were reduced by $12 million, or almost 20 percent, compared with 2001.
22
Our results of operations for the year ended 2002 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted for all of our production and oil sales revenue. As a result of increases in world crude oil prices, partially offset by lower production from the South Monagas Unit, oil sales in Venezuela were 3.8 percent higher in 2002 compared with 2001. Realized fees per barrel increased 4.5 percent (from $12.52 in 2001 to $13.08 in 2002).
Our revenues increased $4.6 million, or 3.6 percent, during the year ended 2002 compared with 2001. This was due to increased oil sales revenue in Venezuela as a result of increases in world crude oil prices, partially offset by lower sales quantities. Our sales quantities for the year ended 2002 from Venezuela were 9.7 MMBbls compared to 9.8 MMBbls for the year ended 2001. The decrease in sales quantities of 100,000 Bbls, or less than 1 percent, was due primarily to logistics and equipment delays in early 2002 at the Tucupita field and the Venezuelan national civil work stoppage which led to the shut-in of our production in late December 2002 for nine days. Average production for the year decreased by less than 775 Bbls per day for the aforementioned reasons.
Our operating expenses decreased $8.8 million, or 21 percent, for the year ended 2002 compared with the year ended 2001. Lower fuel gas, water and oil treatments accounted for $3.4 million of the reduction. Reduced workover expense ($2.6 million) and lower expenses associated with the transportation of Tucupita oil ($5.0 million) with the completion of the Tucupita oil pipeline in late 2001 were offset by $1.1 million of increases in various other categories. Depletion, depreciation and amortization increased $0.8 million, or 4 percent, during the year ended 2002 compared with 2001 primarily due to the first three quarters of 2002 having been calculated on the lower beginning of the year reserves. Depletion expense per barrel of oil produced from Venezuela during 2002 was $2.56 compared with $2.26 during 2001 primarily due to future development costs. We recognized write-downs of capitalized costs of $13.4 million associated with WAB-21 offshore China and $1.1 million for the Lakeside Prospect exploration activities during the year ended 2002 compared with $0.5 million associated with final costs associated with prior exploration activities. General and administrative expenses decreased $3.6 million from 2001 to 2002. The move to Houston was completed in 2001 and overall staff levels were reduced to the current level of ten in Houston. We recognized $3.3 million of income for the partial recovery of prior year bad debt allowance for the funds received from the A.E. Benton bankruptcy. The consideration includes 600,000 shares of stock taken into treasury at a price of $3.56 per share and approximately $1.1 million in cash.
Taxes other than on income decreased $1.3 million, or 24 percent, during the year ended 2002 compared with 2001. This was primarily due to decreased Venezuelan municipal taxes and a one-time adjustment of U.S. employment taxes of $0.7 million.
Investment income and other decreased $1.0 million, or 33 percent, during the year ended 2002 compared with 2001. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $8.6 million, or 34 percent, during the year ended 2002 compared with 2001. We redeemed all $108 million of our 11.625 percent Senior Notes due in May 2003 and purchased $20 million face of the 9.375 percent Senior Notes due in November 2007. In October 2002, we borrowed $15.5 million to finance the construction of the gas pipeline in Venezuela from the Uracoa field to the PDVSA sales line.
Net gain on exchange rates increased $3.8 million, or 493 percent for the year ended 2002 compared with 2001. This was due to the significant devaluation of the Bolivar. We realized income before income taxes and minority interest of $169.8 million during the year ended 2002 compared with $7.2 million in 2001. The increase was dominated by the Arctic Gas Sale. The 2001 income tax benefit related to the potential utilization by the Arctic Gas Sale of net operating loss carry forwards in 2002. Income tax expense decreased $105.0 million due to the reversal of a substantial portion of the valuation allowance on U.S. net operation loss carryforwards in 2001. The effective tax rate in 2002 of 36 percent reflects foreign income taxes incurred on profitable foreign operations and an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the benefit was fully reserved in historical periods. The income before minority interests increased $3.8 million for the year ended 2002 compared with 2001. This was primarily due to the increased profitability (oil prices) and reduced expenses of Benton-Vinccler.
Equity in net earnings of affiliated companies decreased $5.7 million, during the year ended 2002 compared with 2001. This was primarily due to the decreased income from Geoilbent and the elimination of Arctic Gas equity income on April 12, 2002, the date of its sale.
23
Capital Resources and Liquidity
The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see Risk Factors). We require capital principally to service our debt and to fund the following costs:
| • | | drilling and completion costs of wells and the cost of production, treating and transportation facilities; |
|
| • | | geological, geophysical and seismic costs; and |
|
| • | | acquisition of interests in oil and gas properties. |
The amount of available capital will affect the scope of our operations and the rate of our growth. We began selling Venezuelan natural gas in November 2003, but our future rate of growth also depends substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to service our debt.
On February 5, 2003, the Government of Venezuela fixed the exchange rate between the Bolivar and the U.S. dollar, and restricted the ability to exchange Venezuelan Bolivars for U.S. dollars and vice versa. Initially the exchange rate was fixed at 1,600 Venezuelan Bolivars for each U.S. dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar. Oil companies, such as Benton-Vinccler are allowed to receive payments for oil sales in U.S. dollars and pay U.S. dollar-denominated expenses from those payments. The full amount of the Bolivar denominated debt was repaid as of March 31, 2003. As of March 1, 2004, we have cash reserves of approximately $156.0 million and do not expect the currency conversion restriction tokey personnel could adversely affect our ability to meetsuccessfully execute our short-term loan obligations.
Our abilitystrategy.We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to pay interest onexecute our debtbusiness strategy. Loss of one or more key individuals in the organization could hamper or delay achieving our strategy.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. Also during 2004, Harvest Vinccler leased office space in Maturin and general corporate overhead is dependent upon the abilityCaracas, Venezuela for approximately $13,200 and $4,000 per month, respectively. See alsoItem 1 – Businessfor a description of Benton-Vinccler to make loan repayments, dividends and other cash payments to us. However, there have been, and may again be, unforeseeable interruptions inour oil and natural gas properties and reserves.
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, 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. In October 2003, the Court abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.
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 SMU fields are located. A protest to the assessments was filed with the municipality, and in October 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. In July 2006, the Uracoa Municipality issued two additional assessments seeking to impose an increase in tax rates for the last quarter of 2005 and the first quarter of 2006. In August 2006, the Uracoa Municipality issued two further assessments, including penalties, for second quarter 2006 estimated revenues based on the first quarter 2006 oil and natural gas sales
or there may be contractual obligations or legal impediments suchand for supposed errors of Harvest Vinccler as
withholding agent. We dispute all of the
recently instituted currency controls to receiving dividends or distributions from Benton-Vinccler, which could prohibit Benton-Vinccler from remitting funds to us. Management does not tax assessments and17
believe
that the currency controls will prohibit our ability to receive funds from Benton-Vinccler, although were it to do so, our ability to meet our cash requirements would be adversely affected.Debt Reduction.We currentlywe have a significant debt principal obligation payablesubstantial basis for our positions. We are unable to estimate the amount or range of a possible loss.
Libertador Municipality Tax Assessment. In April 2005, Harvest Vinccler received a tax assessment from a tax inspector for the Libertador municipality in 2007 ($85 million). By September 24, 2004, we may be obligated to repay or prepay some portion of this debt with somewhich part of the net cash proceedsSMU fields are located. Harvest Vinccler has submitted a protest to the assessment at the Mayor’s Office, and if no favorable resolution is obtained, it will file a motion with the tax court seeking to enjoin the payment order and dismiss the assessment. We dispute the allegations set forth in the assessment and believe we have a substantial basis for our position. We are unable to estimate the amount or range of a possible loss.
International Arbitration. As a result of the actions taken by PDVSA, the Ministry of Energy and Petroleum (“MEP”) and the SENIAT, in July 2005, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank.
The SENIAT Tax Assessment. In July 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 202 billion Bolivars, or approximately $94 million, related to 2001 through 2004 tax years. We determined not to contest two elements of the claim and made payments totaling 11.3 billion Bolivars, or $5.3 million, in August and September, 2005. During the second quarter 2006, the SENIAT initiated an audit of 2005 tax payments, and in October 2006, Harvest Vinccler received an assessment from the saleSENIAT for 2005 taxes in the amount of Geoilbent (see$15.8 million. In 2006, Harvest Vinccler resolved and substantially paid all of the tax claims made by the SENIAT. Harvest Vinccler paid $73.8 million additional taxes and related interest for the periods of 2001 through first quarter 2006.
Item 4. Submission of Matters to a Vote of Security Holders
At a special meeting of stockholders held on December 18, 2006, the following items were voted on by the stockholders:
| 1. | | Proposal to approve the proposed transaction, including the conversion contract between our subsidiary Harvest Vinccler, S.C.A. and Corporación Venezolana del Petroleo, S.A., and entailing the transfer of substantially all of our assets to Empresa Mixta Petrodelta, S.A., pursuant to the conversion contract: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 30,910,607 | | 133,118 | | 114,731 |
| 2. | | Proposal to postpone or adjourn the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the time of the special meeting to approve the transaction described in proposal 1: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 27,746,888 | | 3,282,231 | | 129,337 |
| 3. | | To vote on such other matters as may properly come before the special meeting or any adjournment or postponement of the special meeting: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 18,457,926 | | 10,894,377 | | 1,806,153 |
18
Risk Factors
We face significant risks in Venezuela. These risks and other risk factors are discussed inItem 1A – Risk FactorsandItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of 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 the subject of a border 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 border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute.
Location and Geology
The WAB-21 contract area is located in the West Wan’an Basin (Nam Con Son) on the South China Sea. Its western edge lies approximately 50 miles southeast of the Dai Hung (Big Bear) Oil Field. The block is to the east of significant natural gas discoveries at Lan Tay and Lan Do, which are reported to contain two trillion cubic feet of natural gas. WAB-21 is also adjacent to the 2005 Thien Ung discovery which tested oil and natural gas and east of the Dua and Blackbird discoveries that successfully tested oil and gas in 2006. The WAB-21 contract area covers several similar structural trends and geological formations, each with potential for hydrocarbon reserves in possible multiple pay zones similar to the known fields and discoveries.
Drilling and Development Activity
Due to the border dispute 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, 2007. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes persist.
Activities by Area
The following table summarizes our consolidated activities by area.
8
| | | | | | | | | | | | | |
| (in thousands) | | Venezuela | | United States | | Total |
Year ended December 31, 2006 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 59,506 | | | | — | | | $ | 59,506 | |
| Total Assets | | $ | 306,289 | | | $ | 116,422 | | | $ | 422,711 | |
| | | | | | | | | | | | | |
Year ended December 31, 2005 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 236,941 | | | | — | | | $ | 236,941 | |
| Total Assets | | $ | 258,268 | | | $ | 142,530 | | | $ | 400,798 | |
| | | | | | | | | | | | | |
Year ended December 31, 2004 | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 186,066 | | | | — | | | $ | 186,066 | |
| Total Assets | | $ | 309,794 | | | $ | 57,692 | | | $ | 367,486 | |
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 period ended March 31, 2006, and years ended December 31, 2005 and 2004. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest.
| | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2006(a) | | 2005 | | 2004 |
Venezuela(b) | | | | | | | | | | | | |
| Crude Oil Production (Bbls) | | | 1,894,101 | | | | 8,762,687 | | | | 8,152,261 | |
| Natural Gas Production (Mcf) | | | 4,506,094 | | | | 25,677,460 | | | | 31,059,416 | |
Average Crude Oil Sales Price ($per Bbl)(c) | | $ | 28.96 | | | $ | 24.02 | | | $ | 18.90 | |
| Average Natural Gas Sales Price ($per Mcf) | | $ | 1.03 | | | $ | 1.03 | | | $ | 1.03 | |
| Average Operating Expenses ($per Boe) | | $ | 3.49 | | | $ | 3.05 | | | $ | 2.50 | |
| | |
| (a) | | Reflects oil and natural gas deliveries through March 31, 2006. |
|
| (b) | | Information represents 100 percent of production. |
|
| (c) | | Average crude oil sales price after hedging activity. |
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; |
|
| • | | tax, environmental, safety and other laws relating to the petroleum industry; |
|
| • | | changes in laws relating to the petroleum industry; |
|
| • | | changes in administrative regulations and the interpretation and application of such rules and regulations; 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, sometimes retroactively, for a variety of political, economic, environmental and9
other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and our potential for economic loss.
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 Bolivar and the U.S. Dollar and restrict the ability to exchange Bolivars for U.S. Dollars and vice versa. The Bolivar is not readily convertible into the U.S. Dollar. We do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the foreseeable future.
No capital expenditures to comply with environmental regulations were required in 2004, 2005 or 2006. Harvest 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) $1.5 million, $9.0 million and $39.2 million in 2006, 2005 and 2004, respectively. Included in these numbers is $8.9 million and $33.5 million for the development of proved undeveloped reserves in 2005 and 2004, respectively.
We have participated in the drilling of wells as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2006 | | 2005 | | 2004 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Wells Drilled: | | | | | | | | | | | | | | | | | | | | | | | | |
| Development: | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | | — | | | | — | | | | 1 | | | | 0.8 | | | | 16 | | | | 12.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Average Depth of Wells (Feet) | | | — | | | | — | | | | — | | | | 4,349 | | | | — | | | | 5,443 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Producing Wells(1): | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude Oil | | | 103 | | | | 82.4 | | | | 108 | | | | 86.4 | | | | 124 | | | | 99.2 | |
| | |
| (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 were conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.
Acreage
The following table summarizes the undeveloped acreage that we hold under concession as of December 31, 2006:
| | | | | | | | | |
| | | Undeveloped |
| | | Gross | | Net |
| China | | | 7,470,080 | | | | 7,470,080 | |
| | | | | | | | | |
10
Title to Undeveloped Acreage
The WAB-21 petroleum contract lies within an area which is the subject of a border dispute between China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with a third party. The border dispute has existed for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the 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.
Competition
We encounter substantial competition from major, national and independent oil and natural gas companies 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 natural gas properties include staff and data necessary to identify, investigate and purchase such properties, the financial resources necessary to acquire and develop such 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, results of operations and cash flows.
Employees
At December 31, 2006, our Houston office had 18 full-time employees. Harvest Vinccler had 240 employees and our Moscow and London offices had 11 and 5 employees, respectively. We augment our staffs from time to time with independent consultants, as required.
Item 1A. Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K, the following factors should be carefully considered when evaluating us.
While approved by our stockholders, the conversion of the OSA to Petrodelta may not be completed and we may not recover our investments or be compensated for our services in Venezuela, and our interests in Venezuela may be unlawfully confiscated by the Venezuelan government.Since April 1, 2006, our operations in Venezuela have continued to be conducted pursuant to the terms of the OSA, which the government no longer recognizes and which it claims is illegal. As such, our future ability to contractually recover all or part of our investments and be compensated for our services depends on completing the process for the conversion of the OSA and transfer of our interests to Petrodelta. If we are unable to convert to Petrodelta, we may not be paid for oil and natural gas produced after March 31, 2006. Further, if we are unable to successfully complete the conversion to Petrodelta, we believe the Venezuelan government will seize our assets and take over Venezuelan operations. Our recourse will be to pursue claims in arbitration for expropriation of our interests or similar claims against the Venezuelan government. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to outcome.
Certain conditions to signing the Conversion Contract may not be met.Before we sign the Conversion Contract, certain conditions must be satisfied, most of which are beyond our control. These conditions include approval by the Venezuelan Ministry of Energy and Petroleum (“MEP”) and the Venezuelan National Assembly; obtaining or filing all necessary consents, authorizations, orders or approvals of governmental authorities; making all necessary filings or registrations with governmental authorities and giving all requisite notifications to governmental authorities; completion of the Conversion Contract and all annexes, including the11
business plan; and the award of the Isleño, Temblador and El Salto fields to Petrodelta by the Venezuelan government.
Until conversion to Petrodelta is complete, we will likely continue to incur expenses without receiving revenues.Even though it is our position that the OSA is still in place, as a result of actions by the government of Venezuela, Harvest Vinccler currently has no recognized agreement setting out its rights and obligations within Venezuela. Harvest Vinccler continues in the day-to-day operations of the SMU fields and continues to incur expenses in doing so; however, there are no contractual means recognized by Venezuela to receive revenues or be reimbursed for costs and expenses during the period prior to the conversion to Petrodelta. Although the MOU provides that upon completion of the conversion, there will be an adjustment between the parties to obtain the same economic result as if the conversion had been completed on April 1, 2006, this adjustment will not occur until and unless the conversion is completed. The timing for completing the conversion to Petrodelta is uncertain. While we continue to maintain cash reserves, our operations in Venezuela represent all of our revenues, and the funds available to pursue our growth strategy may be adversely affected by the financial demands of continued operations in Venezuela during the conversion process.
Until the conversion to Petrodelta is complete and drilling operations resume, our production volumes will continue to decline.Since 2005, our volumes of crude oil and natural gas deliveries have declined significantly. The decline is due to PDVSA’s refusal to allow us to carry out our drilling and facilities program for 2005 and 2006 and the natural decline of the field. Until conversion is completed, the resumption of any significant drilling operations is unlikely and the SMU field’s production volumes will continue to decline.
If the conversion to Petrodelta is completed, we will be a minority interest owner in Petrodelta.Upon conversion of the OSA to Petrodelta and transfer of our assets to Petrodelta, we will be a minority interest owner and no longer have sole control over operations. Our control of Petrodelta will be limited to our rights under the Conversion Contract and its annexes and the Charter and By-Laws of Petrodelta. As a result, our ability to implement our business plan, assure quality control, and set the timing and pace of development may be adversely affected.
If the conversion to Petrodelta is completed, our estimates of reserves may not be realized. Ryder Scott Company, L.P. provided an estimate of reserves attributable to HNR Finance’s interest in the properties to be operated by Petrodelta. We cannot predict whether the volumes of reserves will ultimately be recovered, and volumes of reserves actually recovered may differ significantly from estimated quantities.
If the conversion to Petrodelta is completed, our flexibility in selling or exchanging a direct or indirect interest in Petrodelta to diversify our assets and acquire additional properties may be limited.We continue to look at alternatives to diversify our assets. However, the alternatives are limited. If the conversion to Petrodelta is completed, and we decide to enter into a sale or exchange of all or part of our Venezuelan assets with an unrelated third party, the third party must be approved by the Venezuelan government. The number of potential buyers that will be acceptable to the Venezuelan government may be limited, and this number of potential buyers may be further affected and limited by country risk concerns. Further, a sale or exchange of all or part of our Venezuelan assets after completing the conversion to Petrodelta may be subject to U.S. federal tax consequences.
If the conversion to Petrodelta is completed, CVP and PPSA might not have the funds available to reimburse us for oil and gas deliveries made during the period prior to conversion.Pursuant to the MOU, CVP has agreed to make an economic adjustment to compensate us so as to achieve the same economic result as if the conversion had been completed on April 1, 2006. This adjustment is to occur once the conversion is completed. However, there are no assurances that CVP and PPSA will have adequate funds to make payment to us for the period dating back to April 1, 2006.
The total capital required for development of the fields in Venezuela may exceed the ability of Harvest Vinccler and CVP to finance.Our ability to fully develop the fields in Venezuela will require a significant investment. Our and CVP’s future capital requirements for the development of the SMU fields and the Isleño, Temblador and El Salto fields may exceed the cash available from existing cash flow and cash on hand. Our ability to secure financing is currently limited and uncertain, and has been and may be affected by numerous factors beyond our control, including the risks associated with operating in Venezuela. Because of this financial risk, we12
may not be able to secure either the equity or debt financing necessary to meet our future cash needs for investment, which may limit our ability to fully develop the properties, cause delays with their development or require early divestment of all or a portion of those projects. Failure by us to meet a capital requirement could be a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited.
The loss of key personnel or the ability to establish and retain an experienced and competent workforce in Venezuela could adversely affect our ability to successfully execute our business plan.Our ability to successfully implement the business plan for Petrodelta depends to a large degree on the skills and experience of individuals in key management and operating positions and retaining a capable workforce. We have no assurances that key employees will remain after the conversion to Petrodelta is completed or that Petrodelta will be able to attract and retain competent employees to replace those employees who do not remain with Petrodelta. Moreover, as a minority interest owner in Petrodelta, we have a limited ability to appoint key positions or control decisions on workforce staffing.
Pending conversion to Petrodelta, the actions of CVP, through its members to the Petrodelta board and its appointed General Manager or President, may adversely affect our ability to conduct operations and retain key personnel.
Contracting policies and procedures of Petrodelta could adversely affect successful execution of the business plan.Successful implementation of the business plan of Petrodelta will require the use of skilled and competitively priced contractors for the development of the fields, including the drilling of wells, building of infrastructure and providing essential services. Due to factors such as global competition and the business climate in Venezuela, contractors, labor, and materials and equipment may not be readily available at competitive prices. Further, as a minority interest owner in Petrodelta, our influence over contracting decisions and contracting policies and procedures is limited.
Petrodelta’s business plan will be sensitive to market prices for oil.Petrodelta will be operating under a business plan, the success of which will rely heavily on the market price of oil. To the extent that market values of oil decline, the business plan of Petrodelta may not be successful.
A decline in the market price of crude oil could uniquely affect the financial condition of Petrodelta.Under the terms of the Conversion Contract and other governmental documents, Petrodelta is subject to a special advantage tax (“ventajas especiales”) which requires that if in any year the aggregate amount of royalties, taxes and certain other contributions is less than 50 percent of the value of the hydrocarbons produced, Petrodelta must pay the government the difference. In the event of a significant decline in crude prices, the ventajas especiales could force Petrodelta to operate at a loss. Moreover, our ability to control those losses by modifying the business plan or restricting the budget is limited under the Conversion Contract.
Oil price declines and volatility could adversely affect Petrodelta’s future, our revenue, cash flows and profitability.Prices for oil fluctuate widely. Prices also affect the amount of cash flow available for capital expenditures and dividends from Petrodelta. Any restrictions on future dividends from Petrodelta may impact our ability to service our Venezuelan debt. Lower prices may also reduce the amount of oil that we can produce economically and lower oil production could affect the amount of natural gas we can produce. We cannot predict future oil prices. Factors that can cause fluctuations in oil prices include:
| • | | relatively minor changes in the global supply and demand for oil; |
|
| • | | export quotas; |
|
| • | | market uncertainty; |
|
| • | | the level of consumer product demand; |
|
| • | | weather conditions; |
|
| • | | domestic and foreign governmental regulations and policies; |
|
| • | | the price and availability of alternative fuels; |
|
| • | | political and economic conditions in oil-producing and oil consuming countries; and |
|
| • | | overall economic conditions. |
13
If the conversion to Petrodelta is not completed, our ability to pursue other transactions will be limited.If the conversion to Petrodelta is not completed, we will continue to assess and consider other strategic alternatives for preserving value, including a transfer of all or part of our Venezuelan assets to another party, and we will continue to pursue other business opportunities and investments unrelated to Venezuela. There can be no assurance that we will be able to successfully pursue any such strategic alternatives. Without completion of conversion to Petrodelta, the alternatives available to us are more limited and subject to a number of significant variables.
The legal or fiscal regime for Petrodelta may change and the Venezuelan government may not honor its commitments.While we believe that the Conversion Contract and Petrodelta provide a basis for a more durable arrangement in Venezuela, the value of the business necessarily depends upon Venezuela’s maintenance of legal, tax, royalty and contractual stability. Our recent experiences in Venezuela demonstrate that such stability should not be assumed because the Venezuelan government may not honor its legal and contractual commitments. While we have and will continue to take measures to mitigate our risks, no assurance can be provided that we will be successful in doing so or that events beyond our control will not adversely affect the value of our business in Venezuela.
The actions of the Venezuelan government may cause us to file for international arbitration. As a result of the actions taken by PDVSA, MEP and the SENIAT, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank. An arbitration proceeding may take a number of years to conclude and we can provide no assurances as to its outcome.
Continuing to do business in Venezuela is subject to risk.Our operations in Venezuela are subject to various risks including, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, change in laws, exchange controls, war, insurrection, civil unrest, strikes and other political risks, being subject to foreign laws, legal systems and the exclusive jurisdiction of Venezuelan courts or tribunals, unilateral renegotiation of contracts with the Venezuelan government and changes in laws and policies governing operations of mixed companies. These factors increase our exposure to production disruptions and project execution risk.
Remaining in Venezuela may limit our ability to acquire other oil and gas properties.Under our business plan, Petrodelta may not be a significant source of dividends in its early years. Moreover, our lack of asset diversification and concentration of risk limits our access to both debt and equity capital. Therefore, our near-term growth and diversification must come from unrestricted cash on hand and asset-based lending, rather than cash or debt from our Venezuelan operations. This may limit the size and type of other projects we are able to acquire.
Tax claims by municipalities in Venezuela may adversely affect Harvest Vinccler’s financial condition.The municipalities of Uracoa and Libertador have asserted numerous tax claims against Harvest Vinccler which we believe are without merit. However, the reliability of Venezuela’s judicial system is a source of concern and it can be subject to local and political influences. Accordingly, no assurance can be given that the tax claims will be overturned. Enforcement of the claims through court order requested by the municipalities, even while the claims are under review, could lead to the seizure of Harvest Vinccler’s assets.
Our strategy to focus on Russia and other countries perceived to be politically challenging carries greater deal execution, operating, financial, legal and political risks.While we believe our established presence in countries perceived to be politically challenging and our experience and skills from prior operations position us well for future projects, doing business in Russia and other countries perceived to be politically challenging also carries unique risks. The operating environment is often difficult and the ability to operate successfully will depend on a number of factors, including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of these countries are not mature and their reliability is uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and14
operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have operational and financial control. Recently, the Russian government began to consider legislation to restrict certain “strategic” projects in Russia to majority-owned Russian companies. If adopted, such legislation could adversely affect our ability to acquire projects in Russia consistent with our strategy.
Operations in areas outside the United States are subject to various risks inherent in foreign operations, and our strategy to focus on countries perceived to be politically challenging limits our risk diversification.Our operations 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, including taxes, 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 and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. Our strategy to focus on countries perceived to be politically challenging increases our exposure to operating, financial and political risks.
Our cash position and limited ability to access additional capital may limit our growth opportunities.We have used $88.9 million of our cash as collateral for debt in Venezuela, and, until conversion to Petrodelta, there will be no additional cash available from operations. The unfinished conversion to Petrodelta also significantly limits our access to additional capital, and, after conversion, the concentration of our political risk in Venezuela may limit our ability to leverage our assets. In addition, our future cash position depends upon the payment of dividends by Petrodelta, in particular for the period from April 1, 2006 through the date of conversion. While we believe such dividends, if available, will be paid, there is no assurance this will be the case. These factors may limit our ability to grow through the acquisition of additional oil and gas properties and projects.
Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela is considered a highly inflationary economy. There are many factors which affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Bolivar to the U.S. Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates. The majority of our Venezuelan receipts are denominated in U.S. Dollars. A large portion of our operating and capital expenditures are in U.S. Dollars. For a discussion of currency controls in Venezuela, seeItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources.Successful acquisition of projects in any international country may also expose us to foreign currency risk in that country.
Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Annual Report on Form 10-K contains estimates of our proved oil and natural gas 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. Until we complete the conversion to Petrodelta, we will not have reserves to report under SEC guidelines and, accordingly, no reserves are reported as of December 31, 2006. Moreover, our quantities of proved reserves in 2005 were reduced to remove undeveloped reserves because the actions taken by the Venezuelan government created uncertainty as to whether these reserves would be recovered under the economic and operating conditions which existed in Venezuela (“Contractually Restricted Reserves”).
The process of estimating oil and natural gas reserves is complex requiring 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 likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth. Actual production, revenue, taxes, development expenditures and15
operating expenses with respect to our reserves will likely vary from the estimates used, and these variances may be material.
You should not assume that the present value of future net revenues referred to inNotes to the Consolidated Financial Statements, TABLE V – Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantitiesis 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 natural 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 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 natural gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. We will not have any reserves to report under SEC guidelines until we complete the conversion to Petrodelta or acquire additional properties 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 often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
| • | | unexpected drilling conditions; |
|
| • | | pressure or irregularities in formations; |
|
| • | | equipment failures or accidents; |
|
| • | | weather conditions; |
|
| • | | shortages in experienced labor; |
|
| • | | delays in receiving necessary governmental permits; |
|
| • | | shortages or delays in the delivery of equipment; |
|
| • | | delays in receipt of permits or access to lands; and |
|
| • | | government actions or changes in regulations. |
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 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 risks16
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, national and independent oil and natural gas companies for the acquisition of desirable oil and natural 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 natural 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.
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.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month. Also during 2004, Harvest Vinccler leased office space in Maturin and Caracas, Venezuela for approximately $13,200 and $4,000 per month, respectively. See alsoItem 1 – Businessfor a description of our oil and natural gas properties and reserves.
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, 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. In October 2003, the Court abated the suit pending final judgment of a case pending in Louisiana to which we are not a party. We dispute Excel’s claims and plan to vigorously defend against them. We are unable to estimate the amount or range of any possible loss.
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 SMU fields are located. A protest to the assessments was filed with the municipality, and in October 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. In July 2006, the Uracoa Municipality issued two additional assessments seeking to impose an increase in tax rates for the last quarter of 2005 and the first quarter of 2006. In August 2006, the Uracoa Municipality issued two further assessments, including penalties, for second quarter 2006 estimated revenues based on the first quarter 2006 oil and natural gas sales and for supposed errors of Harvest Vinccler as withholding agent. We dispute all of the tax assessments and17
believe we have a substantial basis for our positions. We are unable to estimate the amount or range of a possible loss.
Libertador Municipality Tax Assessment. In April 2005, Harvest Vinccler received a tax assessment from a tax inspector for the Libertador municipality in which part of the SMU fields are located. Harvest Vinccler has submitted a protest to the assessment at the Mayor’s Office, and if no favorable resolution is obtained, it will file a motion with the tax court seeking to enjoin the payment order and dismiss the assessment. We dispute the allegations set forth in the assessment and believe we have a substantial basis for our position. We are unable to estimate the amount or range of a possible loss.
International Arbitration. As a result of the actions taken by PDVSA, the Ministry of Energy and Petroleum (“MEP”) and the SENIAT, in July 2005, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank.
The SENIAT Tax Assessment. In July 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 202 billion Bolivars, or approximately $94 million, related to 2001 through 2004 tax years. We determined not to contest two elements of the claim and made payments totaling 11.3 billion Bolivars, or $5.3 million, in August and September, 2005. During the second quarter 2006, the SENIAT initiated an audit of 2005 tax payments, and in October 2006, Harvest Vinccler received an assessment from the SENIAT for 2005 taxes in the amount of $15.8 million. In 2006, Harvest Vinccler resolved and substantially paid all of the tax claims made by the SENIAT. Harvest Vinccler paid $73.8 million additional taxes and related interest for the periods of 2001 through first quarter 2006.
Item 4. Submission of Matters to a Vote of Security Holders
At a special meeting of stockholders held on December 18, 2006, the following items were voted on by the stockholders:
| 1. | | Proposal to approve the proposed transaction, including the conversion contract between our subsidiary Harvest Vinccler, S.C.A. and Corporación Venezolana del Petroleo, S.A., and entailing the transfer of substantially all of our assets to Empresa Mixta Petrodelta, S.A., pursuant to the conversion contract: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 30,910,607 | | 133,118 | | 114,731 |
| 2. | | Proposal to postpone or adjourn the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the time of the special meeting to approve the transaction described in proposal 1: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 27,746,888 | | 3,282,231 | | 129,337 |
| 3. | | To vote on such other matters as may properly come before the special meeting or any adjournment or postponement of the special meeting: |
| | | | | |
| | | Against/Withheld | | Abstentions/Broker Non- |
| Votes in Favor | | Votes | | Votes |
| 18,457,926 | | 10,894,377 | | 1,806,153 |
18
PART II
| | |
| Item 5. | | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
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, 2006, there were 37,204,498 shares of common stock outstanding, with approximately 589 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 |
| | 2005 | | | First quarter | | $ | 16.92 | | | $ | 11.30 | |
| | | | | Second quarter | | | 12.48 | | | | 8.13 | |
| | | | | Third quarter | | | 11.68 | | | | 9.00 | |
| | | | | Fourth quarter | | | 10.81 | | | | 8.57 | |
| | | | | | | | | | | | | |
| | 2006 | | | First quarter | | | 10.68 | | | | 8.00 | |
| | | | | Second quarter | | | 14.35 | | | | 9.89 | |
| | | | | Third quarter | | | 14.40 | | | | 9.71 | |
| | | | | Fourth quarter | | | 11.74 | | | | 9.81 | |
On March 2, 2007, the last sales price for the common stock as reported by the NYSE was $9.26 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.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
For securities authorized for issuance under equity compensation plans, seeNotes to the Consolidated Financial Statements Note 5 – Stock Option and Stock Purchase Plans.
STOCK PERFORMANCE GRAPH
The graph below shows the cumulative total stockholder return over the five-year period ending December 31, 2006, assuming an investment of $100 on December 31, 2001 in each of Harvest’s common stock, the Dow Jones U.S. Exploration & Production Index and the S&P Composite 500 Stock Index.
This graph assumes that the value of the investment in Harvest stock and each index was $100 at December 31, 2001 and that all dividends were reinvested.
19
PLOT POINTS
(December 31 of each year)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2001 | | 2002 | | 2003 | | 2004 | | 2005 | | 2006 |
| Harvest Natural Resources, Inc. | | $ | 100 | | | $ | 448 | | | $ | 691 | | | $ | 1,199 | | | $ | 617 | | | $ | 738 | |
| Dow Jones US E&P Index | | $ | 100 | | | $ | 101 | | | $ | 130 | | | $ | 183 | | | $ | 301 | | | $ | 315 | |
| S&P 500 Index | | $ | 100 | | | $ | 77 | | | $ | 97 | | | $ | 106 | | | $ | 109 | | | $ | 124 | |
Total Return Data provided by S&P’s Institutional Market Services, Dow Jones & Company, Inc. is composed of companies that are classified as domestic oil companies under Standard Industrial Classification codes (1300-1399, 2900-2949, 5170-5179 and 5980-5989). The Dow Jones US Exploration & Production Index is accessible at http://www.djindexes.com/mdsidx/index.cfm?event=showTotalMarket.
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, 2006. 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 and 2002 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2003 and 2002.
20
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2006(1) | | | 2005 | | | 2004 | | | 2003 | | | 2002 | |
| | | (in thousands, except per share data) | |
Statement of Operations: | | | | | | | | | | | | | | | | | | | | |
| Total revenues | | $ | 59,506 | | | $ | 236,941 | | | $ | 186,066 | | | $ | 106,095 | | | $ | 126,731 | |
| Operating income | | | 5,499 | | | | 119,525 | | | | 90,480 | | | | 33,627 | | | | 34,585 | |
| Net income (loss) | | | (58,562 | ) | | | 50,839 | | | | 34,360 | | | | 27,303 | | | | 100,362 | |
| Net income (loss) per common share: | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | (1.57 | ) | | $ | 1.38 | | | $ | 0.95 | | | $ | 0.77 | | | $ | 2.90 | |
| | | | | | | | | | | | | | | | |
| Diluted | | $ | (1.57 | ) | | $ | 1.32 | | | $ | 0.90 | | | $ | 0.74 | | | $ | 2.78 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Weighted average common shares outstanding | | | | | | | | | | | | | | | | | | | | |
| Basic | | | 37,225 | | | | 36,949 | | | | 36,128 | | | | 35,332 | | | | 34,637 | |
| Diluted | | | 37,225 | | | | 38,444 | | | | 38,122 | | | | 36,840 | | | | 36,130 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 |
| | | (in thousands) |
Balance Sheet Data: | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 422,711 | | | $ | 400,798 | | | $ | 367,486 | | | $ | 374,348 | | | $ | 335,192 | |
| Long-term debt, net of current maturities | | | 66,977 | | | | — | | | | — | | | | 96,833 | | | | 104,700 | |
Stockholders’ equity(2) | | | 244,886 | | | | 297,512 | | | | 243,189 | | | | 199,713 | | | | 171,317 | |
| | |
| (1) | | Activities under our OSA are reflected under the equity method of accounting effective April 1, 2006. Since such activities are subject to the completion of the conversion to Petrodelta, we have not recorded any net earnings from such activities for the nine months ended December 31, 2006. |
|
| (2) | | No cash dividends were declared or paid during the periods presented. |
21
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
We had a loss of $58.6 million, or $1.57 per diluted share, for the twelve months ended December 31, 2006 compared with earnings of $50.8 million, or $1.32 per diluted share, for 2005. The loss for 2006 is due to the inability to recognize equity earnings for the producing operations in Venezuela since the second quarter of 2006 and charges of $73.8 million for additional taxes and related interest in Venezuela for 2001 through 2006. We will not be able to report the results of our Venezuelan operations in our consolidated financial statements until the conversion to Petrodelta is completed. Although the MOU executed by Harvest Vinccler and CVP in March 2006 provides that upon completion of the conversion there will be an adjustment between the parties to obtain the same economic result as if the conversion had been completed on April 1, 2006, this adjustment will not occur until the conversion is completed.
In 2006, the conversion to Petrodelta has progressed in a number of important areas:
| • | | In August, the MOU was amended to provide for the addition of the Isleño, Temblador and El Salto fields to Petrodelta as additional consideration for our conversion of the OSA to Petrodelta. The addition of these fields is subject to government approval. |
|
| • | | In a special meeting of the stockholders in December 2006, our stockholders approved entering into the transaction contemplated by the MOU. |
|
| • | | Harvest Vinccler has resolved and substantially paid all of the tax claims made by the SENIAT, the Venezuelan income tax authority. We continue to believe that Harvest Vinccler has properly paid all of its taxes, but we understand that resolving the income tax issues with the SENIAT is a necessary step in the transition of Harvest Vinccler’s operations to Petrodelta. |
|
| • | | At the request of PDVSA, Harvest Vinccler invoiced PDVSA for $36.3 million of advanced or accrued costs incurred during the last three quarters of 2006, and $21.2 million, representing the second and third quarter advances, have been reimbursed. The fourth quarter advances of $15.1 million were invoiced to PDVSA in February 2007. |
|
| • | | We have provided CVP with the business plan for the Petrodelta properties. Our plan calls for the immediate resumption of the suspended development of the SMU fields as well as appraisal and development of the Isleño, Temblador and El Salto fields. We are also actively working with CVP on staffing plans for Petrodelta and have reached agreement on other elements of the Conversion Contract. |
Despite this progress, the conversion is not completed, and we can give no assurance with respect to the probability or the timing of completion. The most significant matter to execution of the Conversion Contract and the formation of Petrodelta is the receipt of approvals by the Venezuelan government. Based on our ongoing discussions with Venezuelan officials, we believe that these approvals will be received, but we cannot provide assurance when or if that will occur. However, PDVSA has informed us that a number of other companies have signed their conversion contracts and formed the mixed companies. Moreover, we understand that three companies have completed the conversion process and are now in the position to invoice PDVSA for the crude oil produced since April 1, 2006. With the precedents established and issues resolved by the companies more advanced in the conversion process, we believe that companies such as Harvest Vinccler should be able to expedite the conversion process and the issuance of invoices for payment once we receive the government approvals.
Certain operating statistics for the three and nine month periods ended December 31, 2006, for the SMU fields operated by Harvest Vinccler are set forth below. This information is provided at 100 percent, without reduction for our interest under the OSA or our ownership interest in Petrodelta. While we believe this information to be accurate, no representation is made with respect to what will be reflected in our consolidated financial
22
statements after completing the conversion to Petrodelta. This information may not be representative of future results.
| | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | December 31, 2006 | | December 31, 2006 |
| Oil production (million barrels) | | | 1.6 | | | | 5.2 | |
| Natural gas production (billion cubic feet) | | | 3.6 | | | | 11.5 | |
| Barrels of oil equivalent | | | 2.2 | | | | 7.1 | |
| Cash operating costs ($millions) | | | 11.8 | | | | 28.5 | |
| Capital expenditures ($millions) | | | 2.9 | | | | 3.4 | |
Crude oil delivered from the SMU fields to PDVSA will be priced with reference to Merey 16 published prices, weighted for different markets, and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference priced and prevailing market conditions. Crude oil prices that would be paid for the oil production if the conversion contract were in place cannot yet be calculated as several elements of the pricing formula have not been set. Market prices for crude oil of the type produced in the fields operated by Harvest Vinccler averaged approximately $41.36 and $47.69 a barrel for the three and nine months ended December 31, 2006, respectively. The price for natural gas that would be paid under the conversion contract is $1.54 per thousand cubic feet.
InItem 1 – BusinessandItem 1A – Risk Factors,we discuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. Collectively, the events in Venezuela, both actual and threatened, are having a material adverse effect on our financial condition, results of operations and cash flows. The situation in Venezuela has also restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere. Until there is clarity and certainty over completion of the conversion to Petrodelta, including the receipt of payment for prior crude oil and natural gas deliveries and the resumption of drilling operations, uncertainty over the future of our investment in Venezuela will continue to affect our performance and limit our growth opportunities. We continue to assess and consider alternatives for preserving value, including a possible sale or exchange of all or part of our interests in Venezuela. The alternatives available to us are limited and subject to a number of significant variables, including timing for the completion of conversion to Petrodelta, the value to us of Petrodelta’s assets, governmental approvals and any tax consequences.
We recognize the need to diversify our asset base and that is the primary focus of our strategy. We will use our available cash and future access to capital markets to build a diversified portfolio of assets in a number of countries that fit our strategic investment criteria. We are pursuing opportunities in a number of areas including Russia, the Commonwealth of Independent States, the Middle East and Asia.
In executing our business strategy, we will strive to:
| • | | maintain financial prudence and rigorous investment criteria; |
|
| • | | access capital markets; |
|
| • | | create a diversified portfolio of large assets; |
|
| • | | preserve our financial flexibility; |
|
| • | | use our experience, skills to acquire new projects; and |
|
| • | | keep our organizational capabilities in line with our rate of growth. |
To accomplish our strategy, we intend to:
| • | | Diversify our political risk:Acquire large oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our international investment portfolio. |
|
| • | | Seek Operational and Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments. |
23
| • | | Establish a Presence Through Joint Venture Partners and the Use of Local Personnel:We seek to establish a presence in the countries and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In addition, we use local personnel to help us take advantage of local knowledge and experience and to minimize costs. In pursuing new opportunities, we will seek to enter at an early stage and find local partners in an effort to reduce our risk in any one venture. |
|
| • | | Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure. |
|
| • | | Provide Technical Expertise:We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally. In addition to our in-house technical capabilities, in January 2007 we acquired a minority interest in a technical firm with significant experience in providing leading edge geophysical, geosciences and reservoir engineering services in many places in the world. Through this acquisition we have preferred access to these services. |
|
| • | | Limit Exploration Activities:While our strategy does not focus on unexplored areas, we consider appropriate exploration opportunities that have large potential scale and the ability to manage risk without significant initial cost. |
|
| • | | Maintain A Prudent Financial Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increase our access to debt and equity markets. |
Results of Operations
We include the results of operations of Harvest Vinccler in our consolidated financial statements and reflect the 20 percent ownership interest of Vinccler as a minority interest.
Effective April 1, 2006, our operations have been reflected under the equity method of accounting but our ability to recognize equity earnings for the producing operations in Venezuela are subject to completion of the conversion of the OSA to Petrodelta. There will be an adjustment between the parties to obtain the same economic result as if the conversion had been completed at that date.
The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 2006 and the financial condition as of December 31, 2006 and 2005 in conjunction with our Consolidated Financial Statements and related Notes thereto.
We have presented selected expense items from our consolidated income statement as a percentage of revenue in the following table:
| | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2006 | | 2005 | | 2004 |
| Operating Expenses | | | 16 | % | | | 17 | % | | | 18 | % |
| Depletion, Depreciation and Amortization | | | 18 | | | | 19 | | | | 19 | |
| General and Administrative | | | 44 | | | | 10 | | | | 12 | |
| Taxes Other Than on Income | | | 7 | | | | 3 | | | | 3 | |
| Interest Expense | | | 39 | | | | 1 | | | | 4 | |
24
Years Ended 2006 and 2005
We reported a net loss of $58.6 million, or $1.57 diluted earnings per share, for 2006 compared with net income of $50.8 million, or $1.32 diluted earnings per share, for 2005.
Total expenses and other non-operating (income) expense:
| | | | | | | | | | | | | | | | | |
| | | Year Ended | | | | | | | % | |
| | | December 31, | | | Increase | | | Increase | |
| | | 2006 | | | 2005 | | | (Decrease) | | | (Decrease) | |
| General and administrative | | $ | 26.4 | | | $ | 22.8 | | | | 3.6 | | | | 16 | % |
| Contribution to Science and Technology Fund | | | 3.9 | | | | — | | | | 3.9 | | | | 100 | |
| Account receivable write-off on retroactive oil price adjustment | | | — | | | | 4.5 | | | | (4.5 | ) | | | (100 | ) |
| Taxes other than on income | | | 3.9 | | | | 6.4 | | | | (2.5 | ) | | | (39 | ) |
| Investment income and other | | | (9.4 | ) | | | (4.2 | ) | | | (5.2 | ) | | | 124 | |
| Interest expense | | | 23.2 | | | | 3.4 | | | | 19.8 | | | | 582 | |
| Net (gain) loss on exchange rates | | | 0.1 | | | | (2.8 | ) | | | 2.9 | | | | (104 | ) |
| | | | | | | | | | | | | |
| | | $ | 48.1 | | | $ | 30.1 | | | $ | 18.0 | | | | 60 | % |
| | | | | | | | | | | | | |
General and administrative expenses increased due to higher business development costs and employee related expenses. Taxes other than on income decreased due to the elimination of municipal taxes as a result of the conversion of the OSA to Petrodelta. Interest expense increased due to Harvest Vinccler’s estimated liability for interest on the tax assessments of $52.9 million as well as increased borrowings to pay the tax assessments.
In 2005, Venezuela modified the Science and Technology Law to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela. Harvest Vinccler was unable to estimate the corresponding percentage of the gross revenue for 2005 or the first quarter of 2006 until the regulations were released as many aspects of the law were unclear. In October 2006, the Executive Branch of the Venezuelan government issued the Regulations for the Science and Technology Law which established the methodology for determining the required investment, contribution or expenditure for the 2005 calendar year financial results. After release of the regulations, Harvest Vinccler accrued $3.9 million for the estimated liability for 2005 and the first quarter of 2006 based on its current understanding of the regulations.
Years Ended 2005 and 2004
We reported net income of $50.8 million, or $1.32 diluted earnings per share, for 2005 compared with net income of $34.4 million, or $0.90 diluted earnings per share, for 2004. Below is a discussion of revenues, price and volume variances.
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended | | | | | | | % | | | | |
| | | December 31, | | | Increase | | | Increase | | | | |
| (in millions) | | 2005 | | | 2004 | | | (Decrease) | | | (Decrease) | | | Increase | |
| Revenues | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | $ | 210.5 | | | $ | 154.1 | | | $ | 56.4 | | | | 37 | % | | | | |
| Natural gas | | | 26.4 | | | | 32.0 | | | | (5.6 | ) | | | (18 | ) | | | | |
| | | | | | | | | | | | | | | | | |
| Total Revenues | | $ | 236.9 | | | $ | 186.1 | | | $ | 50.8 | | | | 27 | % | | | | |
| | | | | | | | | | | | | | | | | |
The following table reconciles the net change in revenue:
| | | | | | | | | | | | | | | | | | | | | |
| Price and Volume Variances | | | | | | | | | | | | | | | | | | | | |
| Crude oil price Variance (per Bbl) | | $ | 24.02 | | | $ | 18.90 | | | $ | 5.12 | | | | 27 | % | | $ | 41.6 | |
| Volume Variances | | | | | | | | | | | | | | | | | | | | |
| Crude oil volumes (MBbls) | | | 8,763 | | | | 8,152 | | | | 611 | | | | 7 | % | | $ | 14.7 | |
| Natural gas volumes (MMcf) | | | 25,677 | | | | 31,059 | | | | (5,382 | ) | | | (17 | ) | | | (5.5 | ) |
| | | | | | | | | | | | | | | | | | | | |
| Total volume variances | | | | | | | | | | | | | | | | | | $ | 9.2 | |
| | | | | | | | | | | | | | | | | | | | |
25
Revenue, Crude Oil Price Variance and Volume Variances
Revenues were higher in 2005 compared with 2004 due to increases in world crude oil prices and oil volumes as a result of our second half 2004 drilling program. Price variance is net of the cost of hedges in place during 2005. Natural gas delivery volumes declined due to the refusal of MEP and PDVSA to issue permits for the drilling of new oil wells and the natural decline of associated natural gas from existing oil wells. All natural gas deliveries are associated with the Uracoa oil wells.
Total expenses and other non-operating (income) expense:
| | | | | | | | | | | | | | | | | |
| | | Year Ended | | | | | | | % | |
| | | December 31, | | | Increase | | | Increase | |
| | | 2005 | | | 2004 | | | (Decrease) | | | (Decrease) | |
| Operating expenses | | $ | 39.7 | | | $ | 33.3 | | | $ | 6.4 | | | | 19 | % |
| Depletion and amortization | | | 41.2 | | | | 34.2 | | | | 7.0 | | | | 20 | |
| Depreciation | | | 2.7 | | | | 1.9 | | | | 0.8 | | | | 42 | |
| General and administrative | | | 22.8 | | | | 21.9 | | | | 0.9 | | | | 4 | |
| Account receivable write-off on retroactive oil price adjustment | | | 4.5 | | | | — | | | | 4.5 | | | | 100 | |
| Gain on sale of long-lived assets | | | — | | | | (0.6 | ) | | | 0.6 | | | | 100 | |
| Bad debt recovery | | | — | | | | (0.6 | ) | | | 0.6 | | | | 100 | |
| Taxes other than on income | | | 6.4 | | | | 5.6 | | | | 0.8 | | | | 14 | |
| Investment income and other | | | (4.2 | ) | | | (2.1 | ) | | | (2.1 | ) | | | 100 | |
| Interest expense | | | 3.4 | | | | 7.7 | | | | (4.3 | ) | | | (56 | ) |
| Net (gain) loss on exchange rates | | | (2.8 | ) | | | 0.6 | | | | (3.4 | ) | | | 566 | |
| | | | | | | | | | | | | |
| | | $ | 113.7 | | | $ | 101.9 | | | $ | 11.8 | | | | 12 | % |
| | | | | | | | | | | | | |
Operating expenses increased as a result of higher oil volumes and maintenance work. Depletion and amortization expense per Boe produced during 2005 was $3.16 versus $2.56 in 2004. The increase was due to the exclusion of Contractually Restricted Reserves in our proved reserves as well as other minor revisions. General and administrative expense increased primarily due to penalties accrued for the failure to withhold the prescribed amount of value added taxes from payments to vendors in Venezuela in 2005. Taxes other than on income increased due to increased Venezuelan municipal taxes which result from higher oil revenues.
The effective tax rate increased to 46 percent in 2005 from 41 percent in 2004 primarily due to the payment of $5.3 million related to a partial settlement of the 2001 through 2004 preliminary tax assessment.
Capital Resources and Liquidity
While we can give no assurance, we currently believe that our cash on hand will provide sufficient capital resources and liquidity to fund our business development expenditures and semi-annual interest payment obligations for the next twelve months. InItem 1A – Risk Factors, we discuss a number of variables and risks related to Venezuela that could cause actual results to differ materially and significantly affect our capital resources and liquidity. These risk factors include, but are not limited to, the affects of continued delays in the conversion to Petrodelta, delays or inability of PDVSA to pay for past and future crude oil and natural gas deliveries, the ability to implement our business plan, changes in oil prices, fiscal and contractual stability and expropriation of our assets. We also point out that the total capital required to develop the fields in Venezuela may exceed Harvest Vinccler’s available cash and financing capabilities, and that there may be operational or contractual consequences to this inability. In addition, our ability to acquire and develop growth opportunities outside of Venezuela is dependent upon the ability to receive dividends from Petrodelta and access debt and equity markets.
The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (seeItem 1A — Risk Factors). In 2001, Benton-Vinccler borrowed $12.3 million from aWe require capital principally to fund the acquisition and development of new oil and gas properties.
The amount of available capital will affect the scope of our operations and the rate of our growth. Our future rate of capital resource and liquidity growth also depends substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures.
26
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 Bolivar and the U.S. Dollar and restrict the ability to exchange Bolivars for U.S. Dollars and vice versa. The Bolivar is not readily convertible into the U.S. Dollar. We do not expect the Venezuelan commercial bankcurrency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the constructionforeseeable future.
Our ability to acquire and develop growth opportunities outside of an oil pipeline. A portionVenezuela is dependent upon the ability to receive dividends from Petrodelta and access debt and equity markets.
Debt Reduction.We have semi-annual principal obligations of
$9.8 and $9.3 million on the
loan was denominated in Bolivars and was repaid as of March 31, 2003.Harvest Vinccler loans. We have no other debt obligations.
Working Capital.Our capital resources and liquidity are affected by the
timing of our semiannual interest payments of approximately $4.0 million each May 1 and November 1 on the 9.375 percent Senior Notes due in November 2007 and by receipt of the quarterly payments from PDVSA at the end of the months of February, May, August and November pursuantconversion to
the terms of the operating service agreement for the South Monagas Unit. As a consequence of the timing of these interest payment outflowsPetrodelta and the
PDVSA payment inflows, our cash balances can increase and decrease dramatically on a few dates during the year. In each May and November in particular, interest payments at the beginningability of
the month and PDVSA payments at the end of the month create large swings in our cash balances. Benton-Vinccler’s oil and gas pipeline project loans allow the lenderPetrodelta to accelerate repayment if production ceases for a period greater than thirty days. During the production shut-in which started in December 2002, Benton-Vinccler was granted a waiver of this provision until February 18, 2003 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reduced our net interest expense as the current interest expense was more than the current interest income earned on the invested funds. On February 8, 2003, Benton-Vinccler commenced production, thereby eliminating the need for an additional waiver. A future disruption of production could trigger the debt acceleration provision again. While no assurances can be given, we believe Benton-Vinccler would be able to obtain another waiver under acceptable terms and conditions.
declare dividends.
The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
24
| | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | |
|
| | | (in thousands) |
| | | 2003 | | 2002 | | 2001 |
| | |
| |
| |
|
| Net cash provided by operating activities | | $ | 38,538 | | | $ | 42,627 | | | $ | 36,608 | |
| Net cash provided by (used in) investing activities | | | 38,191 | | | | 126,143 | | | | (48,082 | ) |
| Net cash provided by (used in) financing activities | | | (2,570 | ) | | | (113,293 | ) | | | 5,366 | |
| | | |
| | | |
| | | |
| |
| Net increase (decrease) in cash | | $ | 74,159 | | | $ | 55,477 | | | $ | (6,108 | ) |
| | | |
| | | |
| | | |
| |
| | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | (in thousands) | |
| | | 2006 | | | 2005 | | | 2004 | |
| Net cash provided by (used in) operating activities | | $ | (24,448 | ) | | $ | 114,665 | | | $ | 74,140 | |
| Net cash used in investing activities | | | (90,556 | ) | | | (15,647 | ) | | | (39,684 | ) |
| Net cash provided by (used in) financing activities | | | 100,064 | | | | (20,599 | ) | | | (88,516 | ) |
| | | | | | | | | | |
| Net increase (decrease) in cash | | $ | (14,940 | ) | | $ | 78,419 | | | $ | (54,060 | ) |
| | | | | | | | | | |
At December 31,
2003,2006, we had current assets of
$183.4$199.8 million and current liabilities of
$46.2$82.2 million, resulting in working capital of
$137.2$117.6 million and a current ratio of
4.0:2.4:1. This compares with a working capital of
$97.0$178.1 million and a current
rationratio of
3.8:3.9:1 at December 31,
2002.2005. The
increasedecrease in working capital of
$40.2$60.5 million was primarily due to the
saleinability to reflect the net results of our
minority equity investmentproducing operations in
Geoilbent.Venezuela in our consolidated financial statements for the year ended December 31, 2006 and the charge in the second and third quarters 2006 of $73.8 million for additional taxes and related interest for the impact of income tax assessments by the SENIAT for 2001 through first quarter 2006.
Cash Flow from Operating Activities.Activities. During the
yearsyear ended December 31,
2003 and 2002,2006, net cash used in operating activities was approximately $24.4 million. During the year ended December 31, 2005, net cash provided by operating activities was approximately
$38.5 million and $42.6 million, respectively.$114.7 million. The
$4.1$139.1 million decrease was primarily due to
lowerthe collection of the first quarter accrued oil
revenuesand gas sales receivable which was offset by the
commencement of gas salescharge in the
fourthsecond and third quarters for the estimated tax assessments and related interest, as well as our inability to recognize equity earnings for our producing properties in Venezuela beginning with the second quarter of
2003.2006 under the equity method of accounting pending conversion to Petrodelta.
Cash Flow from Investing Activities.During the
yearsyear ended December 31,
2003 and 2002,2006, we had
limited workover and production-related expenditures and we deposited cash of $94.5 million as collateral for four loans with Venezuelan banks, of which $5.6 million has been returned to us. During the year ended December 31, 2005, we had drilling
workover and production-related capital expenditures of approximately
$60.9$16.1 million and
$43.3 million, respectively. Of the 2003no restricted cash. The decrease in capital expenditures
$33.6 million was attributableis due to the
developmentcontinued suspension of our drilling program and the fact that the conversion of the
South Monagas Unit, $27.0 millionOSA to Petrodelta has not been finalized. The increase in restricted cash is due to collateral for the new borrowings to pay the tax assessments received from the SENIAT and to fund operations. We continue to expend funds during the period prior to the
constructionconversion for workovers and maintenance of the
gas pipelineexisting wells. After the conversion to Petrodelta, our capital commitments will be determined by the business plan provided for in the Conversion Contract and the
balance for other administrative property. The timing and sizeannual budget approved by the Petrodelta Board of capital expenditures forDirectors to implement the South Monagas Unit are entirely atbusiness plan. Outside of Venezuela, our discretion. Our remaining capital commitments worldwide support our search for new acquisitions,business development efforts and are relatively minimal and substantially at our discretion. We will also be required to make annual interest payments of approximately $8.0 million on the 2007 Notes.
27
We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements.
Cash Flow from Financing Activities.During
2003, Benton-Vinccler repaid the
balance of theiryear ended December 31, 2006, Harvest Vinccler borrowed 11 billion Bolivars (approximately $5.0 million) for short term Bolivar denominated
obligations, 105 billion Bolivars (approximately $48.8 million) and 20 billion Bolivars (approximately $9.3 million) for the SENIAT income tax assessments and related interest and 120 billion Bolivars (approximately $55.8 million) for the SENIAT income tax assessments and related interest, to refinance previous borrowings and for operational needs. Also during the year ended December 31, 2006, Harvest Vinccler repaid $5.5 million of its U.S. Dollar debt
(one payment of
$2.2$0.3 million and
other debtfour payments of
$1.2 million.$1.3 million each on the variable rate loans) and 31 billion Bolivars (approximately $14.3 million) of its Bolivar debt. During
2002, we paid $108 million in 11.625 percent senior unsecured notes due May 1, 2003, $20 million in 9.375 percent senior unsecured notes due November 1, 2007 and Benton-Vinccler repaid other debt of $4.3 million. In November 1997, we issued $115 million in 9.375 percent senior unsecured notes due November 1, 2007, of which we repurchased $30 million. Interest on these notes is due May 1 and November 1 of each year. The indenture agreements provide for certain limitations on liens, additional indebtedness, certain investment and capital expenditures, dividends, mergers and sales of assets. Atthe year ended December 31,
2003, we were in compliance with all covenants2005, Harvest Vinccler repaid $6.4 million of
its U.S. Dollar denominated debt (four payments of $0.3 million each and four payments of $1.3 million each on the
indenture.variable rate loans).
Contractual Obligations.Obligations
We have a lease obligation of approximately
$11,000$17,000 per month for our Houston office space. This lease
is validruns through
August 2004. The following table summarizes our contractual obligations at December 31, 2003.| | | | | | | | | | | | | | | | | |
| | | Payments (in thousands) Due by Period |
| | |
|
| | | | | | | Less than | | | | | | | | |
| Contractual Obligation | | Total | | 1 Year | | 1-3 Years | | 3-5 Years |
| |
| |
| |
| |
|
| Long Term Debt | | $ | 103,200 | | | $ | 6,367 | | | $ | 6,367 | | | $ | 90,466 | |
| Office Lease | | | 88 | | | | 88 | | | | — | | | | — | |
| | | |
| | | |
| | | |
| | | |
| |
| Total | | $ | 103,288 | | | $ | 6,455 | | | $ | 6,367 | | | $ | 90,466 | |
| | | |
| | | |
| | | |
| | | |
| |
While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash and marketable securities on hand will provide sufficient capital resources and liquidity to fund our planned capital expenditures, investments in and advances to affiliates, and semiannual interest paymentApril 2014. In addition, Harvest Vinccler has lease obligations for the next 12 months. Our expectation is based upon our current estimate of projected prices, production levels,office space in Maturin and our assumptions that there will be no further disruptions to our productionCaracas, Venezuela for approximately $13,200 and that PDVSA will timely pay our invoices. Actual results could be materially affected if there is a significant change in our expectations or assumptions. Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well
25
as various economic and political conditions that have historically affected the oil and natural gas business. Additionally, prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond our control.
We currently have a significant debt obligation of $85 million payable in November 2007. Our ability to meet our debt obligation and to reduce our level of debt depends on the successful implementation of our business strategy.
$4,000 per month, respectively.
| | | | | | | | | | | | | | | | | | | | | |
| | | Payments (in thousands) Due by Period | |
| | | | | | | Less than | | | | | | | | | | | After 4 | |
| Contractual Obligation | | Total | | | 1 Year | | | 1-2 Years | | | 3-4 Years | | | Years | |
| Long-Term Debt | | $ | 104,651 | | | $ | 37,674 | | | $ | 38,140 | | | $ | 28,837 | | | $ | — | |
| Building Lease | | | 2,775 | | | | 407 | | | | 400 | | | | 412 | | | | 1,556 | |
| | | | | | | | | | | | | | | | |
| Total | | $ | 107,426 | | | $ | 38,081 | | | $ | 38,540 | | | $ | 29,249 | | | $ | 1,556 | |
| | | | | | | | | | | | | | | | |
Effects of Changing Prices, Foreign Exchange Rates and Inflation Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil
and natural gas prices may affect our total planned development activities and capital expenditure program.
As noted above under
Capital Resources and Liquidity, Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February
2004.2004 and again in March 2005. 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 inwith respect to results of operations in Venezuela. With respect to Benton-Vinccler, a significant majority of the sources of funds, including the proceeds from oil sales, our contributions and credit financings, are denominated in U.S. dollars, while a minor amount of local transactions in Venezuela are conducted in local currency. If the rate of increase in the value of the U.S. dollar compared with the Bolivar continues to be less than the rate of inflation in Venezuela, then inflation could be expected to have an adverse effect on Benton-Vinccler.
During the year ended December 31,
2002,2005, our net foreign exchange gain attributable to our international operations was
$4.6$2.8 million. The U.S.
dollarDollar and Bolivar exchange rates were
fixedadjusted in
February 2003 and noMarch 2005. No gains or losses were recognized
afterfrom February
2003.2004 to February 2005. However, there are many factors affecting foreign exchange rates and resulting exchange gains and losses, many of which are beyond our control. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S.
dollar.Dollar. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.
Critical Accounting Policies 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.
Investment in Equity Affiliate
Effective April 1, 2006, our activities under our OSA are reflected under the equity method of accounting. Since such activities are subject to the completion of the conversion of the OSA to Petrodelta, our consolidated financial statements prepared in accordance with GAAP for the year ended December 31, 2006, do not reflect the
28
net results of our producing operations in Venezuela for the last three quarters of the year. We
account forwill not be able to include the results of our
investmentVenezuelan operations in
Geoilbent and Arctic Gas based on a fiscal year ending September 30 priorour consolidated financial statements until the conversion to
their respective sales. Oil and natural gas revenuePetrodelta is accrued monthly based on sales. Each quarter, Benton-Vinccler invoices PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollar contract service fees per barrel.
completed.
We follow the full cost method of accounting for oil and
natural 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
26
and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. A large portion of our proved reserves base from consolidated operations is comprised of oil and gas properties that are sensitive to oil price volatility. We are susceptible to significant upward and downward revisions to our Proved Reserve volumes and values as a result of changes in year end oil and gas prices and the corresponding adjustment to the projected economic life of such properties. Prices for oil and gas are likely to continue to be volatile, resulting in future revision to our Proved Reserve base. We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the SEC. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter and require a write–down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998 other than the write-downs recorded by our equity affiliates. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved reserves will change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.
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.
Our current operations are in Venezuela. The U.S.
dollarDollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in
U.S dollars,U.S. Dollars, and all currency gains or losses are recorded in the statement of operations. We attempt to manage our operations in such a manner as to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past resulting from fluctuations in the relationship of the
Venezuelan Bolivar to the U.S.
dollar.Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.
New Accounting Pronouncements
In
May 2003,February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard
No. 150 “Accounting155 – Accounting for Certain
Hybrid Financial Instruments
with Characteristics(“SFAS 155”), which eliminates the exemption from applying SFAS 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of
both Liabilities and Equity” (the “Statement”). The Statement establishes standardsthe form of the instruments. SFAS 155 also allows the election of fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement event. Adoption is effective for
how an issuer classifies and measures certainall financial instruments
with characteristics of both liabilities and equity. The Statement is generally effective for financial instruments entered intoacquired or
modifiedissued after
May 31, 2003, and otherwise is effective at the beginning of the first
interim period beginningfiscal year that begins after
JuneSeptember 15,
2003.2006. Early adoption is permitted. The adoption of
this Statement had noSFAS 155 will not have a material effect on our consolidated financial
statements.position, results of operations or cash flows.
In January 2003,March 2006, the FASB issued Statement of Financial Accounting Standard 156 – Accounting for Servicing of Financial Assets (“SFAS 156”), which requires all separately recognized servicing assets and servicing liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. Adoption is required as of the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 156 will not have a material effect on our consolidated financial position, results of operations or cash flows.
In July 2006, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 4648 (“FIN 46”48”) Consolidation of Variable Interest Entities, which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE– Accounting for Uncertainty in Income Taxes. FIN 48 is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinatedinterpretation of Statement of Financial Accounting Standard No. 109 – Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial support, or whose equity investors lack the characteristicsstatement recognition and measurement of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has thetax position taken or expected
29
27
majorityto be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. FIN 48 will not impact our consolidated financial position, results of operations and cash flows.
In September 2006, the risks or rewards associated with the VIE.Financial Accounting Standards Board (“FASB”) issued SFAS 157 – Fair Value Measurement (“SFAS 157”) which establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. Adoption is effective for all financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged. SFAS 157 will not have a material effect on our consolidated financial position, results of operations and cash flows.
In December 2003,September 2006, the FASB issued SFAS 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“SFAS 158”) which improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a revision to FIN 46, Interpretation No. 46R (“FIN 46R”), to clarify somedefined benefit postretirement plan as an asset or liability in its statement of the provisions of FIN 46,financial position and to defer certain entities from adopting untilrecognize changes in that funded status in the endyear in which the changes occur through comprehensive income. Adoption is effective as of December 31, 2006, for calendar year corporations with publicly traded equity securities. Earlier application is encouraged. SFAS 158 will not have an effect on our consolidated financial position, results of operations or cash flows.
In September 2006, the first interim or annual reporting period ending after March 15, 2004. ApplicationSEC issued Staff Accounting Bulletin No. 108 (“SAB 108”) regarding the process of FIN 46R is requiredquantifying financial statement misstatements. SAB 108 addresses the diversity in practice in quantifying financial statementsstatement misstatements and the potential under current practice for the build up of public entities thatimproper amounts on the balance sheet. The guidance in SAB 108 did not have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other typesa material effect on our consolidated financial position, results of VIEs is required in financial statements for periods ending after March 15, 2004.operations and cash flows.
Off-Balance Sheet Arrangements
We believe wedo not have no arrangements that would require the application of FIN 46R. We have no materialany off-balance sheet arrangements.
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
and political risk, as discussed below.
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.
Through February 14, 2003, we utilized a costless collar hedge transaction with respect to a portion of our oil production to achieve a more predictable cash flow,In August and
establish an acceptable rate of return on our Tucupita drilling program, as well as to reduce our exposure to price fluctuations. Benton-VincclerSeptember 2004, Harvest Vinccler hedged a portion of its
2003 oil
productionsales for calendar year 2005 by purchasing
atwo WTI crude oil
“put” to protect its 2003 cash flow.puts. Because gains or losses associated with hedging transactions are included in oil sales when the hedged production is delivered, such gains and losses are generally offset by similar changes in the realized prices of the commodities. See
Note 1 – Derivatives and Hedgingfor a complete discussion of our derivative activity.
Currently, we haveWe had no hedging transactions in place for our 2004
or 2006 production.
Total
long-termshort-term debt at December 31,
20032006 of
$96.8$37.7 million consisted of
fixed-rate senior unsecured notes maturing in 2007 ($85.0 million). Benton-Vinccler has $11.8Harvest Vinccler’s Bolivar denominated debt, which had a fixed rate for its initial twelve months. Total short-term debt at December 31, 2005 of $5.5 million
consisted of
Harvest Vinccler U.S.
dollarDollar denominated variable rate
loans.loans, which was all repaid in 2006. A hypothetical 10 percent adverse change in the interest rate would not have a material affect on our results of operations.
Foreign Exchange
30
For
The Bolivar is not readily convertible into the
Venezuelan operations, oil and gas sales are received under a contract in effect through 2012 in U.S.
dollars; expenditures are both in U.S. dollars and local currency.Dollar. We have utilized no currency hedging programs to mitigate any risks associated with operations in
these countries,Venezuela, and therefore our financial results are subject to favorable or unfavorable fluctuations in exchange rates and inflation in
these countries.that country. Venezuela has recently imposed currency exchange controls (see
Capital Resources and Liquidityabove).
Political Risk
Political and economic uncertainty remains very high in Venezuela. During 2003, the production from the South Monagas Unit in Venezuela represented all of our total production from consolidated companies. Our production, revenue and cash flow will be adversely affected if production from the South Monagas Unit decreases significantly for any reason. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA’s inability to accept our oil due to the national civil work stoppage in Venezuela. As a result, 2002 sales were reduced by approximately 0.6 million barrels and 2003 sales were reduced by an estimated 1.2 million barrels. As a result of the Venezuelan national civil work stoppage, the Venezuelan government terminated several thousand PDVSA employees and announced a restructuring of PDVSA’s operations. Throughout 2003, there have been numerous organizational changes in PDVSA. As a result of the situation in PDVSA, its payment to Benton-Vinccler for crude delivered in the fourth quarter of 2002 was late by seven days. However, all other payments have been on time, and we believe PDVSA is committed to building its production levels and returning to more normalized business relations with its customers and suppliers.
28
There are ongoing efforts by opponents of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of the changes and the possible politicalization of PDVSA cannot be predicted, it could adversely affect PDVSA’s ability to manage its contracts and meet its obligations with its suppliers and vendors, such as Benton-Vinccler. Organizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing of those acquisitions. While we have substantial cash reserves to withstand a future disruption of sales, a prolonged loss of sales or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition.
Item 8. Financial Statements and Supplementary Data The information required by this item is included herein on pages S-1 through S-36.S-28.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.
Item 9A. Controls and Procedures The SEC
among other things, adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant’s quarterly and annual reports under the Securities Exchange Act of 1934 (the “Exchange Act”). While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area.
Our principal executive officer There have not been any changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) or 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Evaluation of Disclosure Controls and Procedures.We have established disclosure controls and procedures to ensure that material information relating to us, including our principalconsolidated subsidiaries, is made known to the officers who certify our financial officer have informed us that, based uponreports and to other members of senior management and the Board of Directors.
Based on their evaluation as of December 31, 2003, of2006, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and Ruleor 15d-15(e) under the Exchange Act), they have are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is 1) recorded, processed, summarized and reported within the time periods as specified in the SEC’s rules and forms and 2) accumulated and communicated to our management, including our principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
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 Rule 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
those disclosure controls and procedures are effective. There have been no changes in our internal controls or in other factors known to us that could significantly affect these controls subsequent to their evaluation, nor have we been required to take any corrective actions with regard to any significant deficienciescontrol over financial reporting was effective as of December 31, 2006. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006, and material weaknesses.issued an attestation report which is included herein.
Item 9B. Other Information
None.
31
29
PART III
PART III
Item 10. Directors, and Executive Officers of the Registrantand Corporate Governance
Please refer to the information under the captions “Election of Directors” and “Executive Officers” in our Proxy Statement for the 20042007 Annual Meeting of Shareholders.Stockholders.
Item 11. Executive Compensation Please refer to the information under the caption “Executive Compensation” in our Proxy Statement for the 20042007 Annual Meeting of Shareholders.Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management
| | |
| 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 20042007 Annual Meeting of Shareholders.Stockholders.
Item 13. Certain Relationships and Related Transactions
| | |
| Item 13. | | Certain Relationships and Related Transactions, and Director Independence |
Please refer to the information under the caption “Certain Relationships and Related Transactions” in our Proxy Statement for the 20042007 Annual Meeting of Shareholders.Stockholders.
Item 14. Principal Accounting Fees and Services Please refer to the information under the caption “Independent Accountants”Registered Public Accounting Firm” in our Proxy Statement for the 20042007 Annual Meeting of Shareholders.Stockholders.
32
30
PART IV
PART IV
Item 15. Exhibits and Financial Statement Schedules and Reports on Form 8-K | | | | |
| | | | Page |
| | | |
|
(a) 1. | | Index to Financial Statements: | | |
| | Report of Independent Auditors | | S-1 |
| | Consolidated Balance Sheets at December 31, 2003 and 2002 | | S-2 |
| | Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001 | | S-3 |
| | Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001 | | S-4 |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 | | S-5 |
| | Notes to Consolidated Financial Statements | | S-7 |
2. Consolidated Financial Statement Schedules:
Schedule II - - Valuation and Qualifying Accounts
Schedule III - - Financial Statements and Notes for LLC Geoilbent
| |
| All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto. |
3. Exhibits:
| | | | | | | |
| | | | 3.1 | Page |
| (a)1. | | Index to Financial Statements: | | | Certificate of Incorporation filed September 9, 1988 (Incorporated by reference to Exhibit 3.1 to our Registration Statement (Registration No. 33-26333)). | |
| | | | | | | |
| | | | 3.2 | | | Amendment to Certificate of Incorporation filed June 7, 1991 (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-39214)). | |
| | | | | | | |
| | | | 3.3 | | | Amended and Restated Bylaws as of December 11, 2003.S-2 | |
| | | | | | | |
| | | | 4.1 | | | Form of Common Stock Certificate (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)).S-3 | |
| | | | | | | |
| | | | | | S-4 | |
| | | | | | |
| | | | | S-5 | |
| | | | | | |
| | | | | S-7 | |
2. Consolidated Financial Statement Schedules and Other:
Schedule II — Valuation and Qualifying Accounts
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.
3. Exhibits:
| 3.1 | | Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762.) |
|
| 3.2 | | Amended and Restated Bylaws as of April 6, 2006. (Incorporated by reference to Exhibit 3.2 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.) |
|
| 4.1 | | Form of Common Stock Certificate. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-26333).) |
|
| | 4.2 | | | Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.) |
| | |
| | 4.3 | | | Second Amended and Restated Rights Agreement, dated as of April 15, 2005, between Benton OilHarvest Natural Resources, Inc. and Gas Company and First InterstateWells Fargo Bank, Rights Agent dated April 28, 1995.N.A. (Incorporated by reference to Exhibit 4.14.3 to our Form 10-Q filed on August 13, 2002,April 29, 2005, File No. 1-10762.) |
| | | | | | | |
| | | | 10.1 | | | Form of Employment Agreements (Exhibit 10.19)(Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)). |
| | | | | | |
| | | 10.2 | | | Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission—Exhibit 10.25)(Previously filed as an exhibitCommission. (Incorporated by reference to the exhibits to our S-1 Registration Statement Form S-1 (Registration No. 33-52436).). |
31
| | | | | | |
| | | | 10.3 | | | Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to an aggregate of $115,000,000 principal amount of 9 3/8 percent Senior Notes due 2007 (Incorporated by reference to Exhibit 10.1 to our Form 10-Q for the quarter ended September 30, 1997, File No. 1-10762). |
| | | | | | |
| | | 10.4 | | | Note payable agreement dated March 8, 2001 between Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita Pipeline (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762). |
| | | | | | |
| | | 10.5 | | | Change of Control Severance Agreement effective May 4, 2001 (Incorporated by reference to Exhibit 10.26 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.). |
| | | | | | |
| | | 10.6 | | | Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.). |
33
| | | | | | | |
| | | 10.7 | | | First Amendment to Change of Control Severance Plan effective June 5, 2001 (Incorporated by reference to Exhibit 10.31 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.). |
| | | | | | |
| | | 10.8 | | | Sale and Purchase Agreement dated February 27, 2002 between Benton Oil and Gas Company and Sequential Holdings Russian Investors Limited regarding the sale of Benton Oil and Gas Company’s 68 percent interest in Arctic Gas Company. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on March 28, 2002, File No. 1-10762.) |
| | | | | | |
| | | 10.9 | 10.5 | | 2001 Long Term Stock Incentive PlanPlan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).). |
| | | | | | |
| | | | 10.10 | 10.6 | | Addendum No. 2 to Operating ServicesService Agreement Monagas SUR dated 19th19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
| | | | | | | |
| | 10.7† | | 10.11 | | | Bank Loan Agreement between Banco Mercantil, C.A. and Benton-Vinccler C.A. dated October 1, 2002.Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 10.54.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).) |
|
| 10.8† | | Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
|
| 10.9† | | Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
|
| 10.10† | | Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
|
| 10.11† | | Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
|
| 10.12 | | The Transitory Agreement between Harvest Natural Resources, Inc. and PDVSA Petroleo S.A., dated August 4, 2005. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 8, 2002,October 27, 2005, File No. 1-10762.) |
| | | | | | | |
| | | | 10.12 | | | Guaranty issued by Harvest Natural Resources, Inc. dated September 26, 2002. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
| | | | | | |
| | | 10.13 | † | | Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Peter J. Hill. (Incorporated by reference to Exhibit 10.10 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
| | | | | | |
| | | 10.14 | | | Employment Agreement dated August 1, 2002September 12, 2005 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.1110.2 to our Form 10-Q filed on November 8, 2002,October 27, 2005, File No. 1-10762.) |
| | | | | | | |
| | | | 10.15 | 10.14† | | Employment Agreement dated August 1, 2002September 12, 2005 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.1210.3 to our Form 10-Q filed on November 8, 2002,October 27, 2005, File No. 1-10762.) |
| | | | | | | |
| | | | 10.16 | 10.15† | | Employment Agreement dated August 1, 2002September 12, 2005 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
|
| 10.16† | | Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
|
| 10.17† | | Employment Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
|
| 10.18† | | Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
|
| 10.19† | | Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
34
| 10.20† | | Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
|
| 10.21† | | Employment Agreement dated February 10, 2006 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.1310.1 to our Form 10-Q filed on November 8, 2002,April 20, 2006, File No. 1-10762.) |
| |
| | 10.22 | | Memorandum of Understanding dated March 31, 2006, between Corporación Venezolana del Petroleo, S.A., PDVSA Petroleo, S.A. and Harvest Vinccler, C.A. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.) | | |
| |
| | 10.23 | | 10.17Harvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].) |
|
| 10.24 | | Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
|
| | Sale and Purchase10.25 | | Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
|
| 10.26 | | Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
|
| 10.27 | | Stock Unit Award Agreement dated September 26, 2003,15, 2005 between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regardingJames A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
|
| 10.28 | | Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
|
| 10.29 | | Note Payable agreement dated September 28, 2006 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. Banco Universal related to a principal amount of 105 billion Bolivars with interest at 10.02 percent, for financing of the sale of our 34 percent minority equity investment in LLC Geoilbent.SENIAT assessments. (Incorporated by reference to Exhibit 10.1 to our Form 8-K10-Q filed on October 10, 2003,26, 2006, File No. 1-10762.) |
| |
| | 10.30 | | Note Payable agreement dated October 3, 2006 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. Banco Universal related to a principal amount of 20 billion Bolivars with interest at 10.02 percent, for financing of the SENIAT assessments. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 26, 2006, File No. 1-10762.) | | |
| |
| | 10.31 | | 10.18 | | | Employment AgreementAmendment to Original Memorandum of Understanding dated August 16, 2006, between Corporación Venezolana del Petroleo, S.A. and Harvest Vinccler, C.A. (Incorporated by reference to Appendix C to our Definitive Proxy filed on November 17, 2003 between Harvest Natural Resources, Inc.6, 2006, File No. 1-10762.) |
32
| | | | | | |
| | 10.32 | | | | | Note Payable agreement dated November 20, 2006 between Harvest Vinccler, C.A. and Karl L. Nesselrode.Banesco Banco Universal C.A. related to a principal amount of 120 billion Bolivars with interest at 10.0 percent, for refinancing of the SENIAT assessments and operating requirements. |
| | | | | | |
| | 10.33 | | 21.1Form of 2006 Long Term Incentive Plan Stock Option Agreement – Five Year Vesting, Seven Year Term. |
|
| 21.1 | | List of subsidiaries. |
35
| | | | | | | |
| | | 23.1 | | | Consent of PricewaterhouseCoopers LLP -– Houston |
| | | | | | |
| | | | 23.2 | | | Consent of ZAO PricewaterhouseCoopers Audit - Moscow |
| | | | | | |
| | | 23.3 | | | Consent of Ryder Scott Company, LP |
| | | | | | | |
| | | 31.1 | | | Certification of the Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002 executed by James A. Edmiston, President and Chief Executive Officer. |
| | | | | | | |
| | | 31.2 | | | Certification of the Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer. |
| | |
| | 32.1 | | | CertificationsCertification accompanying the annual reportAnnual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002 executed by James A. Edmiston, President and Chief Executive Officer. |
|
| 32.2 | | Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer. |
| | |
| † | | Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K. |
36
(b) Reports on Form 8-K
On October 10, 2003, we filed a Current Report on Form 8-K disclosing the Unaudited Pro Forma results from the sale of our minority equity investment in Geoilbent.
On November 6, 2003, we filed a Current Report on Form 8-K announcing our third quarter and nine months net income and earnings.
33
REPORT OF INDEPENDENT AUDITORS
Report of Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders of Harvest Natural Resources, Inc.
:
We have completed integrated audits of Harvest Natural Resources, Inc.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, 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 15(a)(1) present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31,
20032006 and
2002,December 31, 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31,
20032006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement
Schedule II – Valuation and Qualifying Accounts listedschedule in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s
management; ourmanagement. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with
auditingthe standards
generally accepted inof the
United States of America, whichPublic Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit
of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the Company changedconsolidated financial statements, the Company’s total consolidated revenues relate to operations in Venezuela. On March 31, 2006, the Company’s Venezuelan subsidiary signed a Memorandum of Understanding (the “MOU”) to convert its Operating Service Agreement to Empresa Mixta Petrodelta S.A. (“Petrodelta”) subject to certain conditions. As of December 31, 2006, a number of the conditions have not been met, and the conversion to Petrodelta has not been completed. Although the MOU provides that upon completion of the conversion, there will be an adjustment between the parties to obtain the same economic result as if the conversion had been completed on April 1, 2006, this adjustment will not occur until the conversion is completed. Upon completion of the conversion, the equity method of accounting is expected to be followed for employee stock-based compensationPetrodelta.
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, 2006 based on criteria established inInternal Control — Integrated Frameworkissued 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, 2006, based on criteria established inInternal Control — Integrated Frameworkissued 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
fair value based method effective January 1, 2003.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
Houston, Texas
March 4, 2004
13, 2007S-1
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | | | |
| | | | | | | December 31, |
| | | | | | |
|
| | | | | | | 2003 | | 2002 |
| | | | | | |
| |
|
| | | | | | | (in thousands, except per |
| | | | | | | share data) |
| | | | | ASSETS | | | | | | | | |
| Current Assets: | | | | | | | | |
| | Cash and cash equivalents | | $ | 138,660 | | | $ | 64,501 | |
| | Restricted cash | | | 12 | | | | 1,812 | |
| | Marketable securities | | | — | | | | 27,388 | |
| | Accounts and notes receivable: | | | | | | | | |
| | | Accrued oil sales | | | 32,766 | | | | 27,359 | |
| | | Joint interest and other, net | | | 11,197 | | | | 8,002 | |
| | Prepaid expenses and other | | | 805 | | | | 2,969 | |
| | | | |
| | | |
| |
| | | | Total Current Assets | | | 183,440 | | | | 132,031 | |
| Restricted Cash | | | 16 | | | | 16 | |
| Other Assets | | | 2,080 | | | | 2,520 | |
| Deferred Income Taxes | | | 4,749 | | | | 4,082 | |
| Investments In and Advances To Affiliated Companies | | | — | | | | 51,783 | |
| Property and Equipment: | | | | | | | | |
| | Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2003 and 2002, respectively) | | | 593,622 | | | | 576,601 | |
| | Other administrative property | | | 8,948 | | | | 7,503 | |
| | | | |
| | | |
| |
| | | | 602,570 | | | | 584,104 | |
| | Accumulated depletion, depreciation, and amortization | | | (418,507 | ) | | | (439,344 | ) |
| | | | |
| | | |
| |
| | | | Net Property and Equipment | | | 184,063 | | | | 144,760 | |
| | | | |
| | | |
| |
| | | $ | 374,348 | | | $ | 335,192 | |
| | | | |
| | | |
| |
| | | | | LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| | Accounts payable, trade and other | | $ | 4,163 | | | $ | 3,804 | |
| | Accounts payable, related party | | | 10,375 | | | | 9,779 | |
| | Accrued expenses | | | 15,251 | | | | 10,865 | |
| | Accrued interest payable | | | 1,427 | | | | 1,405 | |
| | Income taxes payable | | | 8,647 | | | | 6,880 | |
| | Commodity hedging contract | | | — | | | | 430 | |
| | Current portion of long-term debt | | | 6,367 | | | | 1,867 | |
| | | | |
| | | |
| |
| | | | Total Current Liabilities | | | 46,230 | | | | 35,030 | |
| Long-Term Debt | | | 96,833 | | | | 104,700 | |
| Asset Retirement Liability | | | 1,459 | | | | — | |
| Commitments and Contingencies | | | — | | | | — | |
| Minority Interest | | | 30,113 | | | | 24,145 | |
| Stockholders’ Equity: | | | | | | | | |
| Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2003 and 2002; issued 36,405 shares and 35,900 shares at December 31, 2003 and 2002, respectively | | | 364 | | | | 359 | |
| | Additional paid-in capital | | | 175,051 | | | | 173,559 | |
| | Retained earnings | | | 27,537 | | | | 234 | |
| | Treasury stock, at cost, 730 shares and 650 shares at December 31, 2003 and 2002, respectively | | | (3,239 | ) | | | (2,835 | ) |
| | | | |
| | | |
| |
| | | | Total Stockholders’ Equity | | | 199,713 | | | | 171,317 | |
| | | | |
| | | |
| |
| | | $ | 374,348 | | | $ | 335,192 | |
| | | | |
| | | |
| |
| | | | | | | | | |
| | | December 31, | �� |
| | | 2006 | | | 2005 | |
| | | (in thousands, except per | |
| | | share data) | |
| ASSETS | | | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 148,079 | | | $ | 163,019 | |
| Restricted cash | | | 15,888 | | | | — | |
| Accounts and notes receivable: | | | | | | | | |
| Accrued oil and gas sales | | | — | | | | 60,900 | |
| Joint interest and other, net | | | 9,811 | | | | 10,750 | |
| Advances to provisional equity affiliate | | | 19,146 | | | | — | |
| Deferred income tax | | | 5,608 | | | | 3,052 | |
| Prepaid expenses and other | | | 1,246 | | | | 2,149 | |
| | | | | | | |
| Total Current Assets | | | 199,778 | | | | 239,870 | |
| Restricted Cash | | | 73,001 | | | | — | |
| Other Assets | | | 176 | | | | 1,600 | |
| Investment in provisional equity affiliate | | | 146,436 | | | | — | |
| Property and Equipment: | | | | | | | | |
| Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2006 and 2005, respectively) | | | 2,900 | | | | 641,684 | |
| Other administrative property | | | 1,375 | | | | 9,568 | |
| | | | | | | |
| | | | 4,275 | | | | 651,252 | |
| Accumulated depletion, depreciation, and amortization | | | (955 | ) | | | (491,924 | ) |
| | | | | | | |
| Net Property and Equipment | | | 3,320 | | | | 159,328 | |
| | | | | | | |
| | | $ | 422,711 | | | $ | 400,798 | |
| | | | | | | |
| | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| Accounts payable, trade and other | | $ | 3,827 | | | $ | 408 | |
| Accounts payable, related party | | | 9,637 | | | | 9,203 | |
| Accrued expenses | | | 12,975 | | | | 18,444 | |
| Accrued interest | | | 6,850 | | | | 2,637 | |
| Deferred revenue | | | 11,217 | | | | 6,728 | |
| Income taxes payable | | | 34 | | | | 18,909 | |
| Current portion of long-term debt | | | 37,674 | | | | 5,467 | |
| | | | | | | |
| Total Current Liabilities | | | 82,214 | | | | 61,796 | |
| Long-Term Debt | | | 66,977 | | | | — | |
| Asset Retirement Liability | | | — | | | | 2,129 | |
| Commitments and Contingencies | | | | | | | | |
| Minority Interest | | | 28,634 | | | | 39,361 | |
| Stockholders’ Equity: | | | | | | | | |
| Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none | | | | | | | | |
| Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2006 and 2005; issued 37,974 shares and 37,757 shares at December 31, 2006 and 2005, respectively | | | 380 | | | | 378 | |
| Additional paid-in capital | | | 194,176 | | | | 188,242 | |
| Retained earnings | | | 54,174 | | | | 112,736 | |
| Treasury stock, at cost, 770 shares at December 31, 2006 and 2005, respectively | | | (3,844 | ) | | | (3,844 | ) |
| | | | | | | |
| Total Stockholders’ Equity | | | 244,886 | | | | 297,512 | |
| | | | | | | |
| | | $ | 422,711 | | | $ | 400,798 | |
| | | | | | | |
See accompanying notes to consolidated financial statements.
S-2
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| | | | | | | | | | | | | | |
| | | | Years Ended December 31, |
| | | |
|
| | | | 2003 | | 2002 | | 2001 |
| | | |
| |
| |
|
| | | | (in thousands, except per share data) |
Revenues | | | | | | | | | | | | |
| | Oil sales | | $ | 103,920 | | | $ | 127,015 | | | $ | 122,386 | |
| | Gas sales | | | 2,740 | | | | — | | | | — | |
| | Ineffective hedge activity | | | (565 | ) | | | (284 | ) | | | — | |
| | | |
| | | |
| | | |
| |
| | | | 106,095 | | | | 126,731 | | | | 122,386 | |
| | | |
| | | |
| | | |
| |
Expenses | | | | | | | | | | | | |
| | Operating expenses | | | 30,893 | | | | 33,950 | | | | 42,759 | |
| | Depletion, depreciation and amortization | | | 21,188 | | | | 26,363 | | | | 25,516 | |
| | Write-downs of oil and gas properties and impairments | | | 165 | | | | 14,537 | | | | 468 | |
| | General and administrative | | | 15,746 | | | | 16,504 | | | | 20,072 | |
| | Arbitration settlement | | | 1,477 | | | | — | | | | — | |
| | Bad debt recovery | | | (374 | ) | | | (3,276 | ) | | | — | |
| | Taxes other than on income | | | 3,373 | | | | 4,068 | | | | 5,370 | |
| | | |
| | | |
| | | |
| |
| | | | 72,468 | | | | 92,146 | | | | 94,185 | |
| | | |
| | | |
| | | |
| |
| Income from Operations | | | 33,627 | | | | 34,585 | | | | 28,201 | |
| Other Non-Operating Income (Expense) | | | | | | | | | | | | |
| | Gain on disposition of assets | | | 46,619 | | | | 144,029 | | | | — | |
| | Gain on early extinguishment of debt | | | — | | | | 874 | | | | — | |
| | Investment earnings and other | | | 1,418 | | | | 2,080 | | | | 3,088 | |
| | Interest expense | | | (10,405 | ) | | | (16,310 | ) | | | (24,875 | ) |
| | Net gain on exchange rates | | | 529 | | | | 4,553 | | | | 768 | |
| | | |
| | | |
| | | |
| |
| | | | 38,161 | | | | 135,226 | | | | (21,019 | ) |
| | | |
| | | |
| | | |
| |
| Income from Consolidated Companies Before Income | | | | | | | | | | | | |
| | Taxes and Minority Interest | | | 71,788 | | | | 169,811 | | | | 7,182 | |
| Income Tax Expense (Benefit) | | | 9,657 | | | | 60,295 | | | | (35,698 | ) |
| | | |
| | | |
| | | |
| |
| Income Before Minority Interest | | | 62,131 | | | | 109,516 | | | | 42,880 | |
| Minority Interest in Consolidated Subsidiary Companies | | | 5,968 | | | | 9,319 | | | | 5,545 | |
| | | |
| | | |
| | | |
| |
| Income from Consolidated Companies | | | 56,163 | | | | 100,197 | | | | 37,335 | |
| Equity in Net Income (Losses) of Affiliated Companies | | | (28,860 | ) | | | 165 | | | | 5,902 | |
| | | |
| | | |
| | | |
| |
| Net Income | | $ | 27,303 | | | $ | 100,362 | | | $ | 43,237 | |
| | | |
| | | |
| | | |
| |
| Net Income Per Common Share: | | | | | | | | | | | | |
| | Basic | | $ | 0.77 | | | $ | 2.90 | | | $ | 1.27 | |
| | | |
| | | |
| | | |
| |
| | Diluted | | $ | 0.74 | | | $ | 2.78 | | | $ | 1.27 | |
| | | |
| | | |
| | | |
| |
AND COMPREHENSIVE INCOME
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (in thousands, except per share data) | |
Revenues | | | | | | | | | | | | |
| Oil sales | | $ | 54,858 | | | $ | 210,493 | | | $ | 154,075 | |
| Gas sales | | | 4,648 | | | | 26,448 | | | | 31,991 | |
| | | | | | | | | | |
| | | | 59,506 | | | | 236,941 | | | | 186,066 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Expenses | | | | | | | | | | | | |
| Operating expenses | | | 9,241 | | | | 39,723 | | | | 33,324 | |
| Depletion, depreciation and amortization | | | 10,510 | | | | 43,968 | | | | 36,020 | |
| General and administrative | | | 26,421 | | | | 22,819 | | | | 21,857 | |
| Contribution to Science and Technology Fund | | | 3,887 | | | | — | | | | — | |
| Account receivable write-off on retroactive oil price adjustments | | | — | | | | 4,548 | | | | — | |
| Bad debt recovery | | | — | | | | — | | | | (598 | ) |
| Gain on sale of long-lived asset | | | — | | | | — | | | | (578 | ) |
| Taxes other than on income | | | 3,948 | | | | 6,358 | | | | 5,561 | |
| | | | | | | | | | |
| | | | 54,007 | | | | 117,416 | | | | 95,586 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income from Operations | | | 5,499 | | | | 119,525 | | | | 90,480 | |
| Other Non-Operating Income (Expense) | | | | | | | | | | | | |
| Loss on early extinguishment of debt | | | — | | | | — | | | | (2,928 | ) |
| Investment earnings and other | | | 9,406 | | | | 4,205 | | | | 2,085 | |
| Interest expense | | | (23,156 | ) | | | (3,388 | ) | | | (7,749 | ) |
| Net gain (loss) on exchange rates | | | (121 | ) | | | 2,752 | | | | (622 | ) |
| | | | | | | | | | |
| | | | (13,871 | ) | | | 3,569 | | | | (9,214 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income (Loss) from Consolidated Companies Before Income Taxes and Minority Interest | | | (8,372 | ) | | | 123,094 | | | | 81,266 | |
| Income Tax Expense | | | 60,917 | | | | 57,025 | | | | 33,288 | |
| | | | | | | | | | |
| Income (Loss) Before Minority Interest | | | (69,289 | ) | | | 66,069 | | | | 47,978 | |
| Minority Interest in Consolidated Subsidiary Companies | | | (10,727 | ) | | | 15,230 | | | | 13,618 | |
| | | | | | | | | | |
| Net Income (Loss) | | $ | (58,562 | ) | | $ | 50,839 | | | $ | 34,360 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Net Income (Loss) Per Common Share: | | | | | | | | | | | | |
| Basic | | $ | (1.57 | ) | | $ | 1.38 | | | $ | 0.95 | |
| | | | | | | | | | |
| Diluted | | $ | (1.57 | ) | | $ | 1.32 | | | $ | 0.90 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Other comprehensive loss: | | | | | | | | | | | | |
| Unrealized mark to market loss from cash flow hedging activities, net of tax | | | — | | | | — | | | | (487 | ) |
| | | | | | | | | | |
| Comprehensive income (loss) | | $ | (58,562 | ) | | $ | 50,839 | | | $ | 33,873 | |
| | | | | | | | | | |
See accompanying notes to consolidated financial statements.
S-3
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | Retained | | | | | | | | |
| | | | Common | | | | | | Additional | | Earnings | | | | | | | | |
| | | | Shares | | Common | | Paid-in | | (Accumulated | | Treasury | | | | |
| | | | Issued | | Stock | | Capital | | Deficit) | | Stock | | Total |
| | | |
| |
| |
| |
| |
| |
|
Balance at January 1, 2001 | | | 33,872 | | | $ | 339 | | | $ | 156,629 | | | $ | (143,365 | ) | | $ | (699 | ) | | $ | 12,904 | |
| Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | | | |
| | Non-employee director compensation | | | 292 | | | | 3 | | | | 471 | | | | — | | | | — | | | | 474 | |
| Tax benefits related to stock option compensation | | | — | | | | — | | | | 11,008 | | | | — | | | | — | | | | 11,008 | |
| Net Income | | | — | | | | — | | | | — | | | | 43,237 | | | | — | | | | 43,237 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Balance at December 31, 2001 | | | 34,164 | | | | 342 | | | | 168,108 | | | | (100,128 | ) | | | (699 | ) | | | 67,623 | |
| Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | | | |
| | Non-employee director compensation | | | 46 | | | | — | | | | 543 | | | | — | | | | — | | | | 543 | |
| | Employee compensation | | | 175 | | | | 2 | | | | 663 | | | | — | | | | — | | | | 665 | |
| | Exercise of stock options | | | 1,515 | | | | 15 | | | | 4,245 | | | | — | | | | — | | | | 4,260 | |
| Treasury stock (600 shares) | | | — | | | | — | | | | — | | | | — | | | | (2,136 | ) | | | (2,136 | ) |
| Net Income | | | — | | | | — | | | | — | | | | 100,362 | | | | — | | | | 100,362 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Balance at December 31, 2002 | | | 35,900 | | | | 359 | | | | 173,559 | | | | 234 | | | | (2,835 | ) | | | 171,317 | |
| Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exercise of stock options | | | 505 | | | | 5 | | | | 1,196 | | | | — | | | | — | | | | 1,201 | |
| | Employee stock based compensation | | | — | | | | — | | | | 296 | | | | — | | | | — | | | | 296 | |
| Treasury stock (80 shares) | | | — | | | | — | | | | — | | | | — | | | | (404 | ) | | | (404 | ) |
| Net Income | | | — | | | | — | | | | — | | | | 27,303 | | | | — | | | | 27,303 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Balance at December 31, 2003 | | | 36,405 | | | $ | 364 | | | $ | 175,051 | | | $ | 27,537 | | | $ | (3,239 | ) | | $ | 199,713 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | Accumulated | | | | | | | |
| | | Common | | | | | | | Additional | | | | | | | Other | | | | | | | |
| | | Shares | | | Common | | | Paid-in | | | Retained | | | Comprehensive | | | Treasury | | | | |
| | | Issued | | | Stock | | | Capital | | | Earnings | | | Gain(Loss) | | | Stock | | | Total | |
Balance at January 1, 2004 | | | 36,405 | | | $ | 364 | | | $ | 175,051 | | | $ | 27,537 | | | $ | — | | | $ | (3,239 | ) | | $ | 199,713 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exercise of warrants | | | 53 | | | | — | | | | 600 | | | | — | | | | — | | | | — | | | | 600 | |
| Exercise of stock options | | | 1,001 | | | | 10 | | | | 7,381 | | | | — | | | | — | | | | — | | | | 7,391 | |
| Employee stock-based compensation | | | 85 | | | | 1 | | | | 2,151 | | | | — | | | | — | | | | — | | | | 2,152 | |
| Treasury stock (34 shares) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (540 | ) | | | (540 | ) |
| Accumulated other comprehensive loss | | | — | | | | — | | | | — | | | | — | | | | (487 | ) | | | — | | | | (487 | ) |
| Net Income | | | — | | | | — | | | | — | | | | 34,360 | | | | — | | | | — | | | | 34,360 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2004 | | | 37,544 | | | | 375 | | | | 185,183 | | | | 61,897 | | | | (487 | ) | | | (3,779 | ) | | | 243,189 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exercise of stock options | | | 240 | | | | 3 | | | | 829 | | | | — | | | | — | | | | — | | | | 832 | |
| Employee stock-based compensation | | | 74 | | | | — | | | | 2,230 | | | | — | | | | — | | | | — | | | | 2,230 | |
| Treasury stock (5 shares) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (65 | ) | | | (65 | ) |
| Accumulated other comprehensive gain | | | — | | | | — | | | | — | | | | — | | | | 487 | | | | — | | | | 487 | |
| Net Income | | | — | | | | — | | | | — | | | | 50,839 | | | | — | | | | — | | | | 50,839 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2005 | | | 37,858 | | | | 378 | | | | 188,242 | | | | 112,736 | | | | — | | | | (3,844 | ) | | | 297,512 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exercise of stock options | | | 139 | | | | 1 | | | | 879 | | | | — | | | | — | | | | — | | | | 880 | |
| Employee stock-based compensation | | | 80 | | | | 1 | | | | 5,055 | | | | — | | | | — | | | | — | | | | 5,056 | |
| Net Loss | | | — | | | | — | | | | — | | | | (58,562 | ) | | | — | | | | — | | | | (58,562 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2006 | | | 38,077 | | | $ | 380 | | | $ | 194,176 | | | $ | 54,174 | | | $ | — | | | $ | (3,844 | ) | | $ | 244,886 | |
| | | | | | | | | | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements.
S-4
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)| | | | | | | | | | | | | | | | |
| | | | | | Years Ended December 31, |
| | | | | |
|
| | | | | | 2003 | | 2002 | | 2001 |
| | | | | |
| |
| |
|
| | | | | | (in thousands) |
| Cash Flows From Operating Activities: | | | | | | | | | | | | |
| | Net income | | $ | 27,303 | | | $ | 100,362 | | | $ | 43,237 | |
| | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
| | | Depletion, depreciation and amortization | | | 21,188 | | | | 26,363 | | | | 25,516 | |
| | | Write-down and impairment of oil and gas properties | | | 165 | | | | 14,537 | | | | 468 | |
| | | Amortization of financing costs | | | 497 | | | | 1,745 | | | | 1,179 | |
| | | Gain on disposition of assets | | | (46,619 | ) | | | (144,029 | ) | | | (336 | ) |
| | | Equity in net earnings (losses) of affiliated companies | | | 28,860 | | | | (165 | ) | | | (5,902 | ) |
| | | Allowance for employee notes and accounts receivable | | | (169 | ) | | | (2,987 | ) | | | 365 | |
| | | Non-cash compensation related charges | | | 296 | | | | 1,458 | | | | 474 | |
| | | Minority interest in undistributed earnings of subsidiaries | | | 5,968 | | | | 9,319 | | | | 5,545 | |
| | | Gain from early extinguishment of debt | | | — | | | | (874 | ) | | | — | |
| | | Tax benefits related to stock option compensation | | | — | | | | — | | | | 11,008 | |
| | | Deferred income taxes | | | (667 | ) | | | 53,618 | | | | (53,407 | ) |
| | Changes in operating assets and liabilities: | | | | | | | | | | | | |
| | | Accounts and notes receivable | | | (7,935 | ) | | | (1,972 | ) | | | 11,756 | |
| | | Prepaid expenses and other | | | 2,164 | | | | (1,130 | ) | | | 565 | |
| | | Accounts payable | | | 359 | | | | (4,328 | ) | | | (4,671 | ) |
| | | Accounts payable, related party | | | 4,386 | | | | (604 | ) | | | (1,662 | ) |
| | | Accrued interest payable | | | 22 | | | | (2,489 | ) | | | 161 | |
| | | Accrued expenses | | | (76 | ) | | | (9,686 | ) | | | 1,705 | |
| | | Asset retirement liability | | | 1,459 | | | | — | | | | — | |
| | | Commodity hedging contract | | | (430 | ) | | | 430 | | | | — | |
| | | Income taxes payable | | | 1,767 | | | | 3,059 | | | | 607 | |
| | | |
| | | |
| | | |
| |
| | | | Net Cash Provided by Operating Activities | | | 38,538 | | | | 42,627 | | | | 36,608 | |
| | | |
| | | |
| | | |
| |
| Cash Flows from Investing Activities: | | | | | | | | | | | | |
| | Proceeds from sale of investment | | | 69,500 | | | | 189,841 | | | | — | |
| | Additions of property and equipment | | | (60,925 | ) | | | (43,346 | ) | | | (43,364 | ) |
| | Investment in and advances to affiliated companies | | | 2,328 | | | | 9,185 | | | | (16,855 | ) |
| | Increase in restricted cash | | | — | | | | (2,800 | ) | | | (57 | ) |
| | Decrease in restricted cash | | | 1,800 | | | | 1,000 | | | | 10,961 | |
| | Purchases of marketable securities | | | (256,058 | ) | | | (353,478 | ) | | | (15,067 | ) |
| | Maturities of marketable securities | | | 283,446 | | | | 326,090 | | | | 16,370 | |
| | Investment selling costs | | | (1,900 | ) | | | (349 | ) | | | (70 | ) |
| | | |
| | | |
| | | |
| |
| | | Net Cash Provided by (Used In) Investing Activities | | | 38,191 | | | | 126,143 | | | | (48,082 | ) |
| | | |
| | | |
| | | |
| |
| Cash Flows from Financing Activities: | | | | | | | | | | | | |
| | Net proceeds from exercise of stock options | | | 1,201 | | | | 3,345 | | | | — | |
| | Purchase of treasury stock | | | (404 | ) | | | — | | | | — | |
| | Proceeds from issuance of notes payable | | | — | | | | 15,500 | | | | 21,112 | |
| | Payments on notes payable | | | (3,367 | ) | | | (132,138 | ) | | | (15,746 | ) |
| | | |
| | | |
| | | |
| |
| | | Net Cash Provided by (Used In) Financing Activities | | | (2,570 | ) | | | (113,293 | ) | | | 5,366 | |
| | | |
| | | |
| | | |
| |
| | | Net Increase (Decrease) in Cash and Cash Equivalents | | | 74,159 | | | | 55,477 | | | | (6,108 | ) |
| Cash and Cash Equivalents at Beginning of Year | | | 64,501 | | | | 9,024 | | | | 15,132 | |
| | | |
| | | |
| | | |
| |
| Cash and Cash Equivalents at End of Year | | $ | 138,660 | | | $ | 64,501 | | | $ | 9,024 | |
| | | |
| | | |
| | | |
| |
| Supplemental Disclosures of Cash Flow Information: | | | | | | | | | | | | |
| | Cash paid during the year for interest expense | | $ | 13,241 | | | $ | 19,201 | | | $ | 25,721 | |
| | | |
| | | |
| | | |
| |
| | Cash paid during the year for income taxes | | $ | 4,254 | | | $ | 3,935 | | | $ | 3,057 | |
| | | |
| | | |
| | | |
| |
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (in thousands) | |
| Cash Flows From Operating Activities: | | | | | | | | | | | | |
| Net income (loss) | | $ | (58,562 | ) | | $ | 50,839 | | | $ | 34,360 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
| Depletion, depreciation and amortization | | | 10,510 | | | | 43,968 | | | | 36,020 | |
| Amortization of financing costs | | | — | | | | — | | | | 228 | |
| Gain on disposition of assets and investments | | | — | | | | — | | | | (578 | ) |
| Write off of unamortized financing costs | | | — | | | | — | | | | 936 | |
| Account receivable write-off on retroactive oil price adjustments | | | — | | | | 4,548 | | | | — | |
| Allowance for employee notes and accounts receivable | | | — | | | | — | | | | (598 | ) |
| Deferred compensation expense | | | — | | | | (745 | ) | | | 1,521 | |
| Non-cash compensation related charges | | | 5,056 | | | | 2,230 | | | | 2,152 | |
| Minority interest in consolidated subsidiary companies | | | (10,727 | ) | | | 15,230 | | | | 13,618 | |
| Deferred income taxes | | | (2,556 | ) | | | 2,982 | | | | (1,285 | ) |
| Changes in operating assets and liabilities: | | | | | | | | | | | | |
| Accounts and notes receivable | | | 61,839 | | | | (4,481 | ) | | | (27,156 | ) |
| Advances to provisional equity affiliate | | | (19,146 | ) | | | — | | | | — | |
| Prepaid expenses and other | | | 903 | | | | (723 | ) | | | (621 | ) |
| Commodity hedging contract | | | — | | | | 14,947 | | | | (14,947 | ) |
| Accounts payable | | | 3,419 | | | | (8,020 | ) | | | 4,265 | |
| Accounts payable, related party | | | 434 | | | | (1,860 | ) | | | 506 | |
| Accrued expenses | | | (5,469 | ) | | | (10,165 | ) | | | 12,765 | |
| Accrued interest | | | 4,213 | | | | 2,565 | | | | (1,356 | ) |
| Deferred revenue | | | 4,489 | | | | 6,728 | | | | — | |
| Asset retirement liability | | | 24 | | | | 188 | | | | 482 | |
| Income taxes payable | | | (18,875 | ) | | | (3,566 | ) | | | 13,828 | |
| | | | | | | | | | |
| Net Cash Provided By (Used In) Operating Activities | | | (24,448 | ) | | | 114,665 | | | | 74,140 | |
| | | | | | | | | | |
| Cash Flows from Investing Activities: | | | | | | | | | | | | |
| Proceeds from sale of long-lived assets | | | — | | | | — | | | | 578 | |
| Additions of property and equipment | | | (1,657 | ) | | | (16,147 | ) | | | (39,106 | ) |
| Investments in provisional equity affiliates | | | (513 | ) | | | — | | | | — | |
| (Increase) decrease in restricted cash | | | (88,889 | ) | | | 28 | | | | — | |
| Investment costs | | | 503 | | | | 472 | | | | (1,156 | ) |
| | | | | | | | | | |
| Net Cash Used In Investing Activities | | | (90,556 | ) | | | (15,647 | ) | | | (39,684 | ) |
| | | | | | | | | | |
| Cash Flows from Financing Activities: | | | | | | | | | | | | |
| Net proceeds from issuances of common stock | | | 880 | | | | 767 | | | | 7,451 | |
| Proceeds from issuance of notes payable | | | 118,953 | | | | — | | | | — | |
| Payments of note payable | | | (19,769 | ) | | | (6,366 | ) | | | (91,367 | ) |
| Dividend paid to minority interest | | | — | | | | (15,000 | ) | | | (4,600 | ) |
| | | | | | | | | | |
| Net Cash Provided By (Used In) Financing Activities | | | 100,064 | | | | (20,599 | ) | | | (88,516 | ) |
| | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (14,940 | ) | | | 78,419 | | | | (54,060 | ) |
| Cash and Cash Equivalents at Beginning of Year | | | 163,019 | | | | 84,600 | | | | 138,660 | |
| | | | | | | | | | |
| Cash and Cash Equivalents at End of Year | | $ | 148,079 | | | $ | 163,019 | | | $ | 84,600 | |
| | | | | | | | | | |
| Supplemental Disclosures of Cash Flow Information: | | | | | | | | | | | | |
| Cash paid during the year for interest expense | | $ | 23,171 | | | $ | 795 | | | $ | 12,541 | |
| | | | | | | | | | |
| Cash paid during the year for income taxes | | $ | 62,505 | | | $ | 20,991 | | | $ | 11,705 | |
| | | | | | | | | | |
See accompanying notes to consolidated financial statements.
S-5
Supplemental Schedule of Noncash Investing and Financing Activities: For the three years ended December 31, 2003, we recorded an allowance for doubtful accounts related to interest accrued on the remaining amount owed to us by our former chief executive officer, A. E. Benton.
During the year ended December 31, 2003,2006, we reversedissued 0.1 million shares of restricted stock valued at $1.0 million.
During the year ended 2005, we issued 0.1 million shares of restricted stock valued at $0.8 million and Dr. Peter J. Hill, our former Chief Executive Officer, elected to pay withholding tax on a portion2002 restricted stock grant on a cashless basis. This resulted in 5,497 shares being held as treasury stock at cost.
During the year ended 2004, we issued 0.1 million shares of
such allowance as a resultrestricted 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 (“2007 Notes”). Also during the year ended 2004, the holders of our
collectionwarrants elected to exercise 45,000 warrants on a cashless basis by delivering Company shares to us. This resulted in the issuance of
certain amounts owed to the Company including the portions of the note secured by our34,054 shares which are held as treasury stock
and other properties (seeNote 13 – Related Party Transactions).at cost.
See accompanying notes to consolidated financial statements.
S-6
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1 -— Organization and Summary of Significant Accounting Policies Harvest Natural Resources, Inc. is engaged in the exploration, development, production and management of oil and natural gas properties. We conduct our business principally in Venezuela (Benton -Vinccler C.A. or “Benton-Vinccler”through our subsidiary Harvest Vinccler S.C.A. (“Harvest Vinccler”) in which we indirectly own an 80-percent interest. Effective April 1, 2006, our activities under our Operating Service Agreement (“OSA”) are reflected under the equity method of accounting. Since such activities are subject to the completion of the conversion of the OSA to Empresa Mixta Petrodelta S. A. (“Petrodelta”), we have not recorded any net earnings from such activities for the nine months ended December 31, 2006.
On March 31, 2006, Harvest Vinccler signed a Memorandum of Understanding (the “MOU”) with two affiliates of PDVSA, Corporación Venezolana del Petroleo S.A. (“CVP”) and
until September 25, 2003, through our minority equity investmentPDVSA Petroleo S.A. (“PPSA”), to convert the OSA into Petrodelta. Upon receipt of the Venezuelan government approvals contemplated by the MOU, Harvest Vinccler and, we believe, HNR Finance B.V. and CVP will enter into a Contract of Conversion (the “Conversion Contract”). Upon execution of the Conversion Contract, Petrodelta will be formed. Subject to the conditions of the Conversion Contract, the OSA will be cancelled, Harvest Vinccler will transfer substantially all of its tangible assets and contracts, permits and rights related to the Uracoa, Tucupita and Bombal fields (“SMU fields”) in
LLC Geoilbent,Venezuela to Petrodelta and Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the SMU fields, as well as the Isleño, Temblador and El Salto fields which will have been awarded to Petrodelta. Upon completion of conversion, HNR Finance B.V. will have a
Russian entity.40 percent ownership interest in Petrodelta. Since we indirectly own 80 percent of HNR Finance B.V., we will indirectly own a net 32 percent in Petrodelta and Vinccler will indirectly own the remaining eight percent. CVP will own the remaining 60 percent. We have requested CVP to add HNR Finance as a party to the Conversion Contract. Petrodelta will be governed by its own Charter and By-Laws.
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.
dollarDollar is our functional and reporting currency.
Oil and natural gas revenue is accrued monthly based on production and delivery. EachUntil March 31, 2006, each quarter, Benton-Vinccler invoicesHarvest Vinccler invoiced PDVSA Petroleo S.A., an affiliate of Petroleos de Venezuela S.A. (“PDVSA”) or affiliates, based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollarDollar contract service fees per barrel. The operating service agreement providesrelated OSA with PDVSA provided for Benton-VincclerHarvest Vinccler to receive an operating fee for each barrel of crude oil delivered and the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannotcould not exceed the maximum total fee per barrel set forth in the agreement. In August 2005, Harvest Vinccler and PDVSA executed a Transitory Agreement (the “Transitory Agreement”) which provided that the maximum total fee per barrel paid under the OSA could not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement. This limitation was applied retroactively to January 1, 2005 and approximated 47 percent of West Texas Intermediate (“WTI”). The operating fee iswas 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. EachUntil March 31, 2006, each quarter Benton-VincclerHarvest Vinccler also invoicesinvoiced PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Benton-VincclerHarvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil
S-7
stipulated as additional volumes resulting from the
natural gas production (“Incremental Crude Oil”). A portion of the Incremental Crude Oil
iswas invoiced to PDVSA quarterly at a fixed price of $7.00 per Bbl.
The invoices were prepared and submitted to PDVSA by the end of the first month following the end of each calendar quarter, and payment was due from PDVSA by the end of the second month following the end of each calendar quarter. Harvest Vinccler invoiced PDVSA for the first quarter 2006 delivery of its crude oil and natural gas in accordance with the Transitory Agreement. However, Harvest Vinccler recorded deferred revenue of $9.0 million for 2005 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement.
As of December 31, 2006, the conversion to Petrodelta has not been completed due to the lack of approvals by the Venezuelan government. In April 2006, the Venezuelan National Assembly passed legislation terminating all operating service agreements and directing the government to take over the operations carried out by the private companies without prejudice to the incorporation of mixed companies for that purpose. This action, coupled with the unfinished conversion to Petrodelta, has left Harvest Vinccler without a contractual means recognized by the government of Venezuela to address revenues or costs and expenses since March 31, 2006. As a result of this situation, our consolidated financial statements prepared in accordance with generally accepted accounting principals in the United States of America (“GAAP”) for the year ended December 31, 2006 do not reflect the net results of our producing operations in Venezuela for the last three quarters of the year. We will not be able to include the results of our Venezuelan operations in our consolidated financial statements until the conversion to Petrodelta is completed. Although the MOU provides that upon completion of the conversion, there will be an adjustment between the parties to obtain the same economic result as if the conversion had been completed on April 1, 2006, this adjustment will not occur until the conversion is completed. Harvest Vinccler continues in the day-to-day operations of its properties in Venezuela and continues to incur expenses in doing so. The equity method of accounting will be followed for Petrodelta to reflect our net 32 percent interest. During the last three quarters of 2006, Harvest Vinccler advanced or accrued $36.3 million to fund operations. At the request of PDVSA, Harvest Vinccler has invoiced PDVSA for these costs and $21.2 million, representing the second and third quarter advances, have been reimbursed.
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.
At December 31, 2006, Harvest Vinccler had 58.7 billion Venezuela Bolivars (“Bolivars”) which are shown in the December 31, 2006 financial statements as $27.3 million in cash and cash equivalents.
Restricted cash represents cash and cash equivalents
held in U.S. banks used as collateral for
financing, letterHarvest Vinccler’s line of credit and loan agreements, and is classified as current or non-current based on the terms of the agreements.
Marketable Securities
Marketable securities are carried at cost. The marketable securities we may purchase are limited to those defined as Cash Equivalents in the indentures for our senior unsecured note. Cash Equivalents may be comprised of high-grade debt instruments, demand or time deposits, certificates of deposit and commercial paper of highly rated U.S. corporations, all having maturities of no more than 180 days. Our marketable securities at cost, which approximates fair value, consisted of $27.4 million in commercial paper at December 31, 2002.
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SeeNote 2 – Long-Term Debt.
Credit Risk and Operations
All of our total consolidated revenues relate to operations in Venezuela. During the
yearyears ended December 31,
2003,2006 and 2005, our Venezuelan crude oil and
natural gas production represented all of our total production from consolidated companies, and our sole source of revenues related to such Venezuelan production is PDVSA, which maintains full ownership of all hydrocarbons in its fields.
On December 2, 2002, employers’ and workers’ organizations, together with political and civic organizations began a national civic work stoppage, whichBecause the conversion to Petrodelta has
seriously affected many of the country’s economic activities, in particular, the oil industry. As a result of the strike,not been completed, we
were unable to deliver crudehave not been paid by PDVSA for our oil and
hence generate revenues from PDVSA between December 14, 2002 and February 6, 2003. Further, on February 5, 2003, the Venezuelan Government implemented currency exchange controls aimed at restricting the convertibility of the Venezuelan Bolivar and the transfer of funds out of Venezuela. The Venezuelan Government set the exchange rate at 1,600 Bolivars for each U.S. dollar and created a new Currency Exchange Agency which is responsible for the administration of exchange controls. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar. Management believes that we have sufficient cash and does not expect the currency conversion restrictions to adversely affect our ability to meet our short-term obligations.natural gas deliveries since April 1, 2006.
Statement of Financial Accounting Standards No. 133
(“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and hedging activities.
In order for a derivative instrument to qualify for hedge accounting, there must be a clear correlation between the derivative instrument and the forecasted transaction. For all derivatives designated as cash flow hedges, we formally document the relationship between the derivative contract and the hedged item, as well as the risk management objective for entering into the contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. All derivatives are recorded on the balance sheet at fair value. To the extent that the hedge is determined to be effective, changes in the fair value of derivatives for qualifying cash flow hedges are recorded each period in other comprehensive income. Our derivatives
arehave been designated as cash flow hedge transactions in which we hedge the variability of cash flows related to
future oil prices for some or all of our forecasted
transactions. These derivative instruments have been designated as a cash flow hedge and theoil production. The changes in the fair value
hasof theseS-8
derivative instruments have been reported in other comprehensive income assumingbecause the highly effective test was met, and have been reclassified to earnings in the period in which earnings arewere impacted by the variability of the cash flows of the hedged item.
We
measure the hedge effectiveness on a quarterly basis and hedge accounting is discontinued prospectively if it is determined that the derivative ishad no
longer effectivehedging instruments in
offsetting changes in the cash flows of the hedged item. Benton-Vincclerplace for our 2004 or 2006 production. In August 2004, Harvest Vinccler hedged a portion of its 2003 oil sales for calendar year 2005 by purchasing a WTI crude oil “put” to protect its 2003 cash flow. The put was for 10,000 barrels of oil per day for the period of March 1, 2003 through December 31, 2003. This put qualified under the highly effective test. Due to the pricing structure for our Venezuela oil, the put had the economic effect of hedging approximately 20,8005,000 barrels of oil per day. The put cost is $2.50was $4.24 per barrel, or $7.7 million, and had a strike price of $30.00$40.00 per barrel. Settlements of $1.7 million as well as the amortization of the put option cost of $7.7 million have been reflected as a net reduction to oil revenue.
Benton-VincclerIn September 2004, Harvest Vinccler hedged aan additional portion of its 2002calendar year 2005 oil sales by purchasing a commodity contract (costless collar), which required payment to (or receipts from) counterparties based on asecond WTI floor price of $23.00 and a ceiling price of $30.15crude oil put for 6,0005,000 barrels of oil per day. The collarput cost was $3.95 per barrel, or $7.2 million, and had a strike price of $44.40 per barrel. Due to the amended pricing structure as revised by the Transitory Agreement for our Venezuelan oil, these two puts had the economic effect of hedging approximately 21,500 barrels of oil per day for an average of $17.72 per barrel. These puts qualified under the highly effective test.test and the mark-to-market loss at December 31, 2004 was included in other comprehensive loss.
At December 31,
2002, we determined that the underlying2004, Accumulated Other Comprehensive Loss consisted of $0.7 million ($0.5 million net of tax) of unrealized losses on our crude oil
would not be delivered due toputs. Oil sales for the
cessation of production. Accordingly, hedge accounting was discontinued and the valueyear ended 2004 included no losses in settlement of the
derivative wasputs. Deferred net losses recorded
as an oil revenue reduction in
the amount of $0.3 million. The notional amount of each financial instrument is basedAccumulated Other Comprehensive Loss at December 31, 2004 were reclassified to earnings during 2005. All hedging instruments expired under their own terms on expected sales of crude oil production from existing and future development wells and the related incremental oil production associated with production from high gas-to-oil ratio wells after the installation of a gas pipeline. These instruments protect our projected investment return and cash flow derived from our production by reducing the impact of a downward crude oil price movement until their expiration.
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December 31, 2005.
Asset Retirement Liability
Effective January 1, 2003, we adopted
Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). As a result of adopting this statement, Benton-Vinccler recorded under the full cost method of accounting for oil and gas properties an increase in oil and gas properties as well as a corresponding liability in the amount of $4.3 million. This asset retirement obligation is associated with the plugging and abandonment of certain wells in Venezuela. (“SFAS 143143”) requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. Historically, we determined that there would be noNo wells to plug and abandon before returningwere abandoned in the fields to PDVSA. In January 2003, one of our wells suffered a leak in its casing allowing natural gas to flow to the surface. The well was plugged and abandoned and a comprehensive study of all existing wells was undertaken. This study indicated an increased likelihood that we would have to plug and abandon certain of the wells during the term of the agreement. No prior provision was undertaken and no cumulative adjustment was required. We abandoned 11 wells in 2003.years ended December 31, 2006 or 2005. Changes in asset retirement obligations during the yearyears ended December 31, 20032006 and 2005 were as follows:follows (in thousands):
| | | | | |
| Asset retirement obligations as of January 1, 2003 | | $ | — | |
| Liabilities recorded during the first quarter | | | 4,237 | |
| Liabilities settled during the year | | | (733 | ) |
| Revisions in estimated cash flows | | | (2,125 | ) |
| Accretion expense | | | 80 | |
| | | |
| |
| Asset retirement obligations as of December 31, 2003 | | $ | 1,459 | |
| | | |
| |
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2006 | | | 2005 | |
| Asset retirement obligations beginning of period | | $ | 2,129 | | | $ | 1,941 | |
| Liabilities recorded during the period | | | — | | | | 96 | |
| Liabilities settled during the period | | | — | | | | — | |
| Revisions in estimated cash flows | | | (7 | ) | | | (17 | ) |
| Accretion expense | | | 31 | | | | 109 | |
| Reclassified to provisional equity affiliate | | | (2,153 | ) | | | — | |
| | | | | | | |
| Asset retirement obligations end of period | | $ | — | | | $ | 2,129 | |
| | | | | | | |
Accounts and Notes Receivable Allowance for doubtful accounts related to former employee notes at December 31,
20032006 and
20022005 was
$3.4 million and $3.5 million, respectively (seeNote 13 – Related Party Transactions).$2.8 million.
Other assets consist of
costs associated with the issuance of long-term debt and investigative costs associated with new projects.
Debt issuance costs are amortized on a straight-line basis over the life of the debt, which approximates the effective interest method of amortizing these costs. New project costs are reclassified to oil and
natural gas properties or expensed depending on management’s assessment of the likely outcome of the project.
We follow the full cost method of accounting for oil and
natural 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
incurred, including exploration overhead of $0.6 million for the year ended December 31, 2001, and capitalized interest of $0.5 million and $0.9 million for the years ended December 31, 2002 and 2001, respectively. There was no capitalized overhead in 2003 and 2002, and no capitalized interest in 2003.incurred. Only overhead that is directly identified with acquisition,
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exploration or development activities are capitalized. All costs related to production, general corporate overhead and similar activities are expensed as incurred.
The costs of unproved properties are excluded from amortization until the properties are evaluated. At least
annuallyquarterly we evaluate our unproved properties on a country by country basis for possible impairment. If we abandon all exploration efforts in a country where no proved reserves are assigned, all exploration and acquisition costs associated with the country are expensed.
During 2003, 2002 and 2001, we recognized $0.2 million, $14.5 million and $0.5 million, respectively, in impairments associated with former exploration prospects and the China WAB-21 block. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.
Excluded costs at December 31,
20032006 consisted of property acquisition costs in the amount of $2.9 million which were all incurred prior to 2001. All of the excluded costs at December 31,
20032006 relate to the acquisition of Benton Offshore China Company and exploration related to its WAB-21 property. The ultimate timing of when the costs related to the acquisition of Benton Offshore China Company will be included in amortizable costs is uncertain.
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Statement of Financial Accounting Standards No. 141 – Business Combinations (“FAS 141”) and No. 142 – Goodwill and Other Intangible Assets (“FAS 142”) included new terminology on the disclosure of what constitutes an intangible asset. One interpretation being considered relative to these standards is that a mineral interest associated with proved and undeveloped oil and gas leasehold acquisition costs should be classified separately in Oil and Gas Properties on the Consolidated Balance Sheet as intangible assets, and the disclosures required by FAS 141 and FAS 142 would be included in the Notes to Financial Statements. We believe that the presentation and disclosure of the $2.9 million excluded costs attributed to the China cost center is appropriate pending further guidance on this matter.
All capitalized costs (including oilfield inventory and future abandonment costs under SFAS 143) and estimated future development costs (including estimated dismantlement, restoration and abandonment costs) of proved reserves are depleted using the units of production method based on the total proved reserves of the country cost center. Depletion expense, which was substantially all attributable to the Venezuelan cost center for the years ended December 31, 2003, 20022006, 2005 and 20012004 was $19.6$9.9 million, $24.9$41.2 million and $22.1$34.1 million ($2.52,3.74, $3.16 and $2.56 and $2.26 per equivalent barrel), respectively.
A gain or loss is recognized on the sale of oil and
natural gas properties only when the sale involves a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved property.
Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was
$1.6$0.6 million,
$1.4$2.8 million and
$3.4$1.9 million for the years ended December 31,
2003, 20022006, 2005 and
2001,2004, respectively.
The major components of property and equipment at December 31 are as follows (in thousands):
| | | | | | | | | | | | | | | | |
| | | 2003
| | 2002
| | 2006 | | 2005 | |
| Proved property costs | | $ | 582,456 | | $ | 566,415 | | | $ | — | | 630,634 | |
| Costs excluded from amortization | | 2,900 | | 2,900 | | | 2,900 | | 2,900 | |
| Material and supply inventories | | 8,266 | | 7,286 | | |
| Oilfield inventories | | | — | | 8,150 | |
| Other administrative property | | 8,948 | | 7,503 | | | 1,375 | | 9,568 | |
| | |
| |
| | | | | | |
| | | 602,570 | | 584,104 | | | 4,275 | | 651,252 | |
| Accumulated depletion, impairment and depreciation | | | (418,507 | ) | | | (439,344 | ) | | | (955 | ) | | | (491,924 | ) |
| | |
| |
| | | | | | |
| | | $ | 184,063 | | $ | 144,760 | | | $ | 3,320 | | $ | 159,328 | |
| | |
| |
| | | | | | |
We perform a quarterly cost center ceiling test of our oil and
natural 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
2003. Equity2006 or 2005. We have reclassified our oil and natural gas properties to investment 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.provisional equity affiliate.
At December 31,
20032006 and
2002,2005, we had several stock-based employee compensation plans, which are more fully described in
Note 65 – Stock Option and Stock Purchase Plans. Prior to 2003, we accounted for those plans under the recognition and measurement provisions of
APBAccounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Effective January 1, 2003, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards Statement No. 123 (“FAS 123”), Accounting for Stock-Based Compensation
as amended by Statement of Financial accounting Standards No. 148 (“SFAS 148”), prospectively to all employee awards granted, modified, or settled after January 1, 2003.
EffectiveS-10
January 1, 2005, we adopted Statement of Financial Accounting Standard 123 (revised 2004) Share-Based Payment (“SFAS 123R”) to all employee awards granted, modified, or settled after October 1, 2005. The effect of the adoption of SFAS 123R was not material. Awards under our plans vest in periodic installments after one year of their grant and expire ten years from grant date. Therefore, the costs related to stock-based employee compensation included in the determination of net income in the years ended December 31,
20032005 and
20022004 are less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of FAS 123. The following table illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period.
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| | | | | | | | | |
| | | 2005 | | | 2004 | |
| | | (in thousands, except per share data) | |
| Net income, as reported | | $ | 50,839 | | | $ | 34,360 | |
| | | | | | | | | |
| Add: Stock-based employee compensation cost, net of tax | | | 2,635 | | | | 999 | |
| | | | | | | | | |
| Less: Total stock-based employee compensation cost determined under fair value based method, net of tax | | | (2,711 | ) | | | (1,382 | ) |
| | | | | | | |
| | | | | | | | | |
| Net income – proforma | | $ | 50,763 | | | $ | 33,977 | |
| | | | | | | |
| Net income per common share: | | | | | | | | |
| Basic – as reported | | $ | 1.38 | | | $ | 0.95 | |
| | | | | | | |
| Basic – proforma | | $ | 1.37 | | | $ | 0.94 | |
| | | | | | | |
| | | | | | | | | |
| Diluted – as reported | | $ | 1.32 | | | $ | 0.90 | |
| | | | | | | |
| Diluted – proforma | | $ | 1.32 | | | $ | 0.89 | |
| | | | | | | |
| | | | | | | | | | | | | |
| | | 2003
| | 2002
| | 2001
|
| Net income, as reported | | $ | 27,303 | | | $ | 100,362 | | | $ | 43,237 | |
| Add: Stock-based employee compensation cost, net of tax | | | 296 | | | | 915 | | | | 35 | |
| Less: Total stock-based employee compensation cost determined under fair value based method, net of tax | | | (1,056 | ) | | | (2,905 | ) | | | (2,459 | ) |
| | | |
| | | |
| | | |
| |
| Net income – proforma | | $ | 26,543 | | | $ | 98,372 | | | $ | 40,813 | |
| | | |
| | | |
| | | |
| |
| Net income per common share: | | | | | | | | | | | | |
| Basic – as reported | | $ | 0.77 | | | $ | 2.90 | | | $ | 1.27 | |
| | | |
| | | |
| | | |
| |
| Basic – proforma | | $ | 0.75 | | | $ | 2.87 | | | $ | 1.20 | |
| | | |
| | | |
| | | |
| |
| Diluted – as reported | | $ | 0.74 | | | $ | 2.78 | | | $ | 1.27 | |
| | | |
| | | |
| | | |
| |
| Diluted – proforma | | $ | 0.72 | | | $ | 2.75 | | | $ | 1.20 | |
| | | |
| | | |
| | | |
| |
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carryforwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
In the third quarter of 2003, a portion of the valuation allowance was reversed based on the utilization of net operating losses which offset U.S. taxable income generated by the sale of our minority equity investment in Geoilbent. We have
significant operations outside of the United States, principally in
Venezuela and, until September 25, 2003, a minority equity investment in Russia.Venezuela. The U.S.
dollarDollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S.
dollars,Dollars, and all currency gains or losses are recorded in the statement of operations. We attempt to manage our operations in a manner to reduce our exposure to foreign exchange losses. However, there are many factors that affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We have recognized significant exchange gains and losses in the past, resulting from fluctuations in the relationship of the Venezuelan currency to the U.S.
dollar.Dollar. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.
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
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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 payment for the fourth quarter 2002 sales, which was due February 28, 2003, was delayed until March 7, 2003, which was approximately seven days late due to the effect of the national civil work stoppage on PDVSA. The book values of all financial instruments, other than long-term debt, are representative of their fair values due to their short-term maturities. The aggregate fair value of our senior unsecured notes, based on the last trading prices at December 31, 2003 and 2002, was approximately $85.0 million and $77.4 million, respectively.
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
mark-to-S-11
market gains/(losses)mark-to-market losses from cash flow hedging activities as other comprehensive income/(loss)loss during the yearsyear ended December 31, 20032004 and 2002.
in accordance with SFAS 130, have provided a separate line in the audited consolidated statement of operations and comprehensive income.
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
May 2003,February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard
No. 150 “Accounting155 – Accounting for Certain
Hybrid Financial Instruments
with Characteristics(“SFAS 155”), which eliminates the exemption from applying SFAS 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of
both Liabilities and Equity” (the “Statement”). The Statement establishes standardsthe form of the instruments. SFAS 155 also allows the election of fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement event. Adoption is effective for
how an issuer classifies and measures certainall financial instruments
with characteristics of both liabilities and equity. The Statement is generally effective for financial instruments entered intoacquired or
modifiedissued after
May 31, 2003, and otherwise is effective at the beginning of the first
interim period beginningfiscal year that begins after
JuneSeptember 15,
2003.2006. Early adoption is permitted. The adoption of
this Statement had noSFAS 155 will not have a material effect on our consolidated financial
statements.position, results of operations or cash flows.
In January 2003,March 2006, the FASB issued Interpretation No. 46Statement of Financial Accounting Standard 156 – Accounting for Servicing of Financial Assets (“FIN 46”SFAS 156”) 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 thatrequires all separately recognized servicing assets and servicing liabilities be initially measured at fair value. SFAS 156 permits, but does not have sufficient equity investmentrequire, the subsequent measurement of servicing assets and servicing liabilities 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 VIEfair value. Adoption is the enterprise that has the majorityrequired as of the risksbeginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 156 will not have a material effect on our consolidated financial position, results of operations or rewards associated with the VIE.cash flows.
In December 2003,July 2006, the FASB issued a revision to FIN 46,Financial Interpretation No. 46R48 (“FIN 46R”48”), – Accounting for Uncertainty in Income Taxes. FIN 48 is an interpretation of Statement of Financial Accounting Standard No. 109 – Accounting for Income Taxes. FIN 48 was issued to clarify some ofcreate a single model to address accounting for uncertainty in tax positions. FIN 48 clarifies 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 46Raccounting for income taxes by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements of public entities that have interestsstatements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in structures that are commonly referred to as special-purpose entitiesinterim periods, disclosure and transition. FIN 48 is effective for periods endingfiscal years beginning after December 15, 2003. Application2006. FIN 48 will impact our consolidated financial position, results of operations and cash flows.
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 157 – Fair Value Measurement (“SFAS 157”) which establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. Adoption is effective for all other types of VIEs is required in financial statements issued for fiscal years beginning after November 15, 2007, and interim periods ending after March 15, 2004. We believe wewithin those fiscal years. Earlier application is encouraged. SFAS 157 will not have no arrangementsa material effect on our consolidated financial position, results of operations and cash flows.
In September 2006, the FASB issued SFAS 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“SFAS 158”) which improves financial reporting by requiring an employer to recognize the over funded or under funded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that would requirefunded status in the year in which the changes occur
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through comprehensive income. Adoption is effective as of December 31, 2006, for calendar year corporations with publicly traded equity securities. Earlier application is encouraged. SFAS 158 will not have an effect on our consolidated financial position, results of FIN 46R. Weoperations or cash flows.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (“SAB 108”) regarding the process of quantifying financial statement misstatements. SAB 108 addresses the diversity in practice in quantifying financial statement misstatements and the potential under current practice for the build up of improper amounts on the balance sheet. The guidance in SAB 108 did not have
noa material
off-balance sheet arrangements.effect on our consolidated financial position, results of operations and cash flows.
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of AmericaGAAP 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
natural gas reserve volumes and the future development costs. Actual results could differ from those estimates.
Certain items in
20012004 and
20022005 have been reclassified to conform to the
20032006 financial statement presentation.
Note 2 — Investments In and Advances To Affiliated Companies On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited and recognized a pre-tax gain on the sale of $46.6 million (seeNote 9 – Russian Operations). Prior to the sale, our 34 percent minority equity investment in Geoilbent was accounted for using the equity method due to the significant influence we exercised over their operations and management. Investments included amounts paid to the investee company for shares of stock and other costs incurred associated with the acquisition and evaluation of technical data for the oil fields operated by the investee company. Equity in earnings of Geoilbent is based on a fiscal year ending September 30. No dividends have been paid to us from Geoilbent.
Equity in earnings and losses and investments in and advances to Geoilbent are as follows (in thousands):
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| | | | | | | | | |
| | | LLC Geoilbent
|
| | | 2003
| | 2002
|
| Investments: | | | | | | | | |
| In equity in net assets | | $ | — | | | $ | 28,056 | |
| Other costs, net of amortization | | | — | | | | (263 | ) |
| | | |
| | | |
| |
| Total investments | | | — | | | | 28,319 | |
| Advances | | | — | | | | 2,527 | |
| Equity in earnings | | | — | | | | 20,937 | |
| | | |
| | | |
| |
| Total | | $ | — | | | $ | 51,783 | |
| | | |
| | | |
| |
Note 3 — Long-Term Debt and Liquidity
Long-term debt consists of the following (in thousands):
| | | | | | | | | |
| | | December 31, | | December 31, |
| | | 2003
| | 2002
|
| Senior unsecured notes with interest at 9.375% | | | | | | | | |
| See description below | | $ | 85,000 | | | $ | 85,000 | |
| Note payable with interest at 6.1% | | | | | | | | |
| See description below | | | 2,700 | | | | 3,900 | |
| Note payable with interest at 39.7% | | | | | | | | |
| See description below | | | — | | | | 2,167 | |
| Note payable with interest at 7.1% | | | 15,500 | | | | 15,500 | |
| | | |
| | | |
| |
| | | | 103,200 | | | | 106,567 | |
| Less current portion | | | 6,367 | | | | 1,867 | |
| | | |
| | | |
| |
| | | $ | 96,833 | | | $ | 104,700 | |
| | | |
| | | |
| |
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2006 | | | 2005 | |
| Note payable with interest at 10.0% | | $ | 55,814 | | | $ | — | |
| Note payable with interest at 10.0% | | | 39,535 | | | | — | |
| Note payable with interest at 10.0% | | | 9,302 | | | | — | |
| Note payable with interest at 9.0% | | | — | | | | 300 | |
| Note payable with interest at 11.5% | | | — | | | | 5,167 | |
| | | | | | | |
| | | | 104,651 | | | | 5,467 | |
| | | | | | | | | |
| Less current portion | | | 37,674 | | | | 5,467 | |
| | | | | | | |
| | | $ | 66,977 | | | $ | — | |
| | | | | | | |
In
On September 15, 2006, Harvest Vinccler entered into a short term line of credit with a Venezuelan bank for 11 billion Bolivars (approximately $5.0 million). The line of credit was due March 19, 2007, and had a fixed interest rate of 10.5 percent. The line of credit was collateralized by a $5.6 million deposit in a U.S. bank to cover the line of credit and accrued interest. The line of credit was used to meet short term Bolivar denominated obligations. The line of credit was repaid on November 1997, we issued $115.0 million in 9.375 percent senior unsecured notes due November 1, 2007 (“2007 Notes”), of which we repurchased $30.0 million. Interest on the 2007 Notes24, 2006.
On September 27, 2006, Harvest Vinccler entered into a three year term loan with a Venezuelan bank for 105 billion Bolivars (approximately $48.8 million). The first principal payment is due
May 1 and November 1 of each year. At December 31, 2003, we were360 days after the funding date in
compliance with all covenants of the
indenture. In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan commercial bank, for construction of an oil pipeline. The loan is in two parts, with the first part in an original principal amount of $6.0 million that bears interest payable monthly based on 90-day London Interbank Borrowing Rate (“LIBOR”) plus 5 percent with principal payable quarterly for five years. The second part,21 billion Bolivars (approximately $9.8 million), and 21 billion Bolivars (approximately $9.8 million) every 180 days thereafter. A payment in the original principal amount of 4.420 billion Venezuelan Bolivars (“Bolivars”) (approximately $6.3$9.3 million). The Bolivar loan was repaid as of March 31, 2003. The loans provide for certain limitationsmade on mergers and sale of assets. We have guaranteed the repayment of this loan.
In October 2002, Benton-Vinccler, C.A. executed a note and borrowed $15.5 million to fund construction of a gas pipeline and related facilities to deliver natural gas from the Uracoa field to a PDVSA pipeline.December 18, 2006. The interest rate for thisthe first year is fixed at 10.0 percent and will be negotiated for the second year subject to a maximum of 95 percent of the average interest rate charged by six major Venezuelan banks. This loan is 90-day LIBOR plus 6 percentage points.collateralized by a $40.0 million deposit in a U.S. bank. The term is four years with a quarterly amortization of $1.3 million beginning with the first quarter 2004 to coincide with the first payment from our gas sales.
Benton-Vinccler’s oil and gas pipeline project loans allow the lender to accelerate repayment if production ceases for a period greater than thirty days. During the production shut-in which started in December 2002, Benton-Vincclerloan was granted a waiver of this provision until February 18, 2003 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reduced our net interest expense as the current interest expense was more than the current interest income earned on the invested funds. On February 8, 2003, Benton-Vinccler commenced production, thereby eliminating the need for an additional waiver. A future disruption of production could trigger the debt acceleration provision again. While no assurances can be given, we believe Benton-Vinccler would be able to obtain another waiver.
The terms of the 2007 Notes require that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the sale, or any amount not so invested must be used to repay or prepaymeet the 2007 Notes or certain debts of subsidiaries.
SENIAT income tax assessments and related interest. S-13
On October 3, 2006, Harvest Vinccler entered into a term loan with a Venezuelan bank for 20 billion Bolivars (approximately $9.3 million). The loan matures in 180 days at a fixed interest rate of 10.0 percent. The loan was used to meet the SENIAT income tax assessments and related interest. This loan is collateralized by a $7.7 million deposit in a U.S. bank.
On November 20, 2006, Harvest Vinccler entered into a three year term loan with a Venezuelan bank for 120 billion Bolivars (approximately $55.8 million). The first principal payment
requirementsis due 180 days after the funding date in the amount of 20 billion Bolivars (approximately $9.3 million), and 20 billion Bolivars (approximately $9.3 million) every 180 days thereafter. The interest rate for
our long-term debt outstandingthe first 180 days is fixed at
December 31, 2003 are as follows (in thousands):| | | | | |
| 2004 | | $ | 6,367 | |
| 2005 | | | 6,367 | |
| 2006 | | | 5,466 | |
| 2007 | | | 85,000 | |
| | | |
| |
| | | $ | 103,200 | |
| | | |
| |
Liquidity
We currently have10.0 percent and may be adjusted from time to time thereafter within the limits set forth by the Central Bank of Venezuela or in accordance with the conditions in the financial market. The loan is collateralized by a significant debt obligation payable$40.4 million deposit in November 2007 of $85 million. Our abilitya U.S. bank. The loan will be used to meet our debt obligationsthe SENIAT income tax assessments and related interest, refinance a portion of the Bolivar loan and to reduce our level of debt depends on the successful implementation of our strategic objectives. Our cash flow from operations complemented with our cash and cash equivalents of $139 million at December 31, 2003, can be invested in other opportunities used to develop our significant proved undeveloped reserves or used to repurchase our outstanding debt.
fund operating requirements.
Note 43 — Commitments and Contingencies We have employment contracts with
fivesix executive officers which provide for annual base salaries, eligibility for bonus compensation and various benefits. The contracts provide for a lump sum payment as a multiple of base salary in the event of termination of employment without cause. In addition, these contracts provide for payments as a multiple of base salary and bonus,
excise tax reimbursement and a continuation of benefits in the event of termination without cause following a change in control. By providing one year notice, these agreements may be terminated by either party on May 31,
2005.2008.
In
July 2001,April 2004, we
leasedsigned a ten-year lease for
three years office space in Houston, Texas, for approximately
$11,000$17,000 per month.
We lease 17,500 square feet ofAlso during 2004, Harvest Vinccler leased office space in
a California building that we no longer occupy under a lease agreement that expires in December 2004, all of which has been subleasedMaturin and Caracas, Venezuela for
rents that approximate our lease costs.$13,200 and $4,000 per month, respectively.
Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Benton-Vinccler, C.A., Gale Campbell and Sheila Campbell in the District Court for Harris County, Texas.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. TheIn October 2003, 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. We are unable to estimate the amount or range of any possible loss.
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 SMU fields are located. A protest to the assessments was filed with the municipality, and in October 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. In July 2006, the Uracoa Municipality issued two additional assessments seeking to impose an increase in tax rates for the last quarter of 2005 and the first quarter of 2006. In August 2006, the Uracoa Municipality issued two further assessments, including penalties, for second quarter 2006 estimated revenues based on the first quarter 2006 oil and natural gas sales and for supposed errors of Harvest Vinccler as withholding agent. 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 a possible loss.
Libertador Municipality Tax Assessment. In April 2005, Harvest Vinccler received a tax assessment from a tax inspector for the Libertador municipality in which part of the SMU fields are located. Harvest Vinccler has submitted a protest to the assessment at the Mayor’s Office, and if no favorable resolution is obtained, it will file a motion with the tax court seeking to enjoin the payment order and dismiss the assessment. We dispute the allegations set forth in the assessment and believe we have a substantial basis for our position. We are unable to estimate the amount or range of a possible loss.
S-14
International Arbitration. As a result of the actions taken by PDVSA, the Ministry of Energy and Petroleum (“MEP”) and the SENIAT, in July 2005, we delivered formal notices to Venezuelan government officials of an investment dispute under Venezuelan law and bilateral investment treaties entered into by the government of Venezuela. The bilateral investment treaties and Venezuelan law provide for international arbitration of investment disputes conducted through the International Centre for Settlement of Investment Disputes of the World Bank.
The SENIAT Tax Assessment. In July 2005, the SENIAT, the Venezuelan income tax authority, issued a preliminary tax assessment to Harvest Vinccler of 202 billion Bolivars, or approximately $94 million, related to 2001 through 2004 tax years. We determined not to contest two elements of the claim and made payments totaling 11.3 billion Bolivars, or $5.3 million, in August and September, 2005. During the second quarter 2006, the SENIAT initiated an audit of 2005 tax payments, and in October 2006, Harvest Vinccler received an assessment from the SENIAT for 2005 taxes in the amount of $15.8 million. In 2006, Harvest Vinccler resolved and substantially paid all of the tax claims made by the SENIAT. Harvest Vinccler paid $73.8 million additional taxes and related interest for the periods of 2001 through first quarter 2006.
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
iswill have a material
to us.adverse impact on our financial condition, results of operations and cash flows.
Taxes Other Than on Income Benton-Vinccler pays a
Harvest Vinccler paid municipal taxtaxes through the first quarter 2006 on operating fee revenues it receivesreceived under the OSA for productiondeliveries from the South Monagas Unit. The year ended December 31, 2002 included a non-recurring foreign payrollSMU fields. In September 2006, PDVSA remitted to the Uracoa municipality an additional $1.0 million in municipal taxes based on the new tax adjustment of $0.7 million.rates from amounts that had been withheld by PDVSA from Harvest Vinccler’s first quarter 2006 oil and natural gas sales for other purposes. The components of taxes other than on income were (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003
| | 2002
| | 2001
| | 2006 | | 2005 | | 2004 | |
| Venezuelan municipal taxes | | $ | 2,741 | | $ | 3,805 | | $ | 4,447 | | | $ | 3,191 | | $ | 5,788 | | $ | 4,485 | |
| Franchise taxes | | 341 | | 139 | | 121 | | | 175 | | | (70 | ) | | 464 | |
| Payroll and other taxes | | 291 | | 124 | | 802 | | | 582 | | 640 | | 612 | |
| | |
| |
| |
| | | | | | | | |
| | | $ | 3,373 | | $ | 4,068 | | $ | 5,370 | | | $ | 3,948 | | $ | 6,358 | | $ | 5,561 | |
| | |
| |
| |
| | | | | | | | |
S-14
Contribution to Science and Technology Fund
In 2005, Venezuela modified the Science and Technology Law to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela.
In October 2006, the Executive Branch issued the Regulations for the Science and Technology Law which established the methodology for determining the required investment, contribution or expenditure for the 2005 calendar year financial results. Harvest Vinccler was unable to estimate the corresponding percentage of the gross revenue for 2005 or the first quarter of 2006 until the regulations were released as many aspects of the law were unclear. After release of the regulations, Harvest Vinccler accrued $3.9 million for the estimated liability for 2005 and the first quarter of 2006 based on its current understanding of the regulations. After March 31, 2006, Harvest Vinccler believes it will not have any gross revenue subject to this law. The regulation provides that the amount that is not invested, contributed or spent must be deposited with an official agency created to administrate the law which has yet to be formed. It is possible that there will be a legal challenge to the regulations.
The tax effects of significant items comprising our net deferred income taxes as of December 31,
20032006 and
20022005 are as follows (in thousands):
| | | | | | | | | |
| | | 2003
| | 2002
|
| Deferred tax assets: | | | | | | | | |
| Operating loss carryforwards | | $ | 20,442 | | | $ | 19,690 | |
| Difference in basis of property | | | 29,602 | | | | 21,495 | |
| Other | | | 3,070 | | | | 2,043 | |
| Valuation allowance | | | (48,365 | ) | | | (39,146 | ) |
| | | |
| | | |
| |
| Net deferred tax asset | | $ | 4,749 | | | $ | 4,082 | |
| | | |
| | | |
| |
S-15
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| Deferred tax assets: | | | | | | | | |
| Operating loss carryforwards | | $ | 7,466 | | | $ | 2,020 | |
| Difference in basis of assets | | | 25,343 | | | | 25,343 | |
| Deferred revenue | | | 5,608 | | | | 3,052 | |
| Valuation allowance | | | (32,809 | ) | | | (27,363 | ) |
| | | | | | | |
| Net deferred tax asset | | | 5,608 | | | | 3,052 | |
| Less current portion | | | 5,608 | | | | 3,052 | |
| | | | | | | |
| | | $ | — | | | $ | — | |
| | | | | | | |
The valuation allowance increased by
$9.2$5.5 million as a result of the change in the U.S. deferred tax assets related to the net operating loss
carryforward as well as a Venezuelan deferred tax asset impairment.carryforward. Realization of deferred tax assets associated with net operating loss carryforwards is dependent upon generating sufficient taxable income prior to their expiration. Management believes it is more likely than not that they will not be realized through future taxable income.
The difference in interpretation of oil pricing under the OSA has been recognized and represents our entire deferred tax asset.
The components of income before income taxes and minority interest are as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003
| | 2002
| | 2001
| | 2006 | | 2005 | | 2004 | |
| Income (loss) before income taxes | | |
| United States | | $ | 21,812 | | $ | 89,455 | | $ | (26,572 | ) | | $ | (15,688 | ) | | $ | 8,178 | | $ | (16,593 | ) |
| Foreign | | 49,976 | | 80,356 | | 33,754 | | | 7,316 | | 114,916 | | 97,859 | |
| | |
| |
| |
| | | | | | | | |
| Total | | $ | 71,788 | | $ | 169,811 | | $ | 7,182 | | | $ | (8,372 | ) | | $ | 123,094 | | $ | 81,266 | |
| | |
| |
| |
| | | | | | | | |
The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003
| | 2002
| | 2001
| | 2006 | | 2005 | | 2004 | |
| Current: | | |
| United States | | $ | 1,188 | | $ | 353 | | $ | 1 | | | $ | — | | $ | 739 | | $ | (8 | ) |
| Foreign | | 9,136 | | 6,324 | | 6,700 | | | 63,473 | | 53,304 | | 34,581 | |
| | |
| |
| |
| | | | | | | | |
| | | $ | 10,324 | | $ | 6,677 | | $ | 6,701 | | | 63,473 | | 54,043 | | 34,573 | |
| | |
| |
| |
| | |
| Deferred: | | |
| United States | | $ | — | | $ | 53,413 | | | (42,405 | ) | |
| Foreign | | | (667 | ) | | 205 | | 6 | | | | (2,556 | ) | | 2,982 | | | (1,285 | ) |
| | |
| |
| |
| | | | | | | | |
| | | | (667 | ) | | 53,618 | | | (42,399 | ) | | $ | 60,917 | | $ | 57,025 | | $ | 33,288 | |
| | |
| |
| |
| | | | | | | | |
| | | $ | 9,657 | | $ | 60,295 | | $ | (35,698 | ) | |
| | |
| |
| |
| | |
During 2003, we reduced our foreign tax provision approximately $3.9 million related to the resolution of certain prior year foreign income tax matters. Additionally, we recorded a domestic tax provision of approximately $1.1 million related to certain domestic tax matters identified during the year.
A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):
| | | | | | | | | | | | | |
| | | 2003
| | 2002
| | 2001
|
| Computed tax expense at the statutory rate | | $ | 15,025 | | | $ | 59,348 | | | | 4,580 | |
| State income taxes | | | 1,188 | | | | 353 | | | | — | |
| Effect of foreign source income and rate differentials on foreign income | | | (15,849 | ) | | | (19,373 | ) | | | 1,675 | |
| Change in valuation allowance | | | 9,219 | | | | 19,446 | | | | (53,413 | ) |
| Prior year adjustments | | | — | | | | — | | | | 2,304 | |
| Reclass paid-in capital | | | — | | | | — | | | | 11,007 | |
| All other | | | 74 | | | | 80 | | | | 215 | |
| | | |
| | | |
| | | |
| |
| Sub-total income tax expense (benefit) | | | 9,657 | | | | 59,854 | | | | (33,632 | ) |
| Effects of recording equity income of certain affiliated Companies on an after-tax basis | | | — | | | | 441 | | | | (2,066 | ) |
| | | |
| | | |
| | | |
| |
| Total income tax expense (benefit) | | $ | 9,657 | | | $ | 60,295 | | | $ | (35,698 | ) |
| | | |
| | | |
| | | |
| |
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| Computed tax expense at the statutory rate | | $ | (2,930 | ) | | $ | 43,083 | | | $ | 28,443 | |
| State income taxes | | | — | | | | — | | | | 25 | |
| Effect of foreign source income and rate differentials on foreign income | | | 8,563 | | | | 16,065 | | | | (2,169 | ) |
| Change in valuation allowance | | | 5,446 | | | | 13,129 | | | | 7,020 | |
| Alternative minimum tax | | | — | | | | 739 | | | | — | |
| Venezuela tax settlement | | | 49,793 | | | | — | | | | — | |
| Net operating loss utilization | | | — | | | | (15,567 | ) | | | — | |
| Other | | | 45 | | | | (424 | ) | | | (31 | ) |
| | | | | | | | | | |
| Total income tax expense | | $ | 60,917 | | | $ | 57,025 | | | $ | 33,288 | |
| | | | | | | | | | |
Rate differentials for foreign income result from tax rates different from the U.S. tax rate being applied in foreign
jurisdictions and from the effect of foreign currency devaluation in foreign subsidiaries which use the U.S. dollar as their functional currency.S-15
jurisdictions.
At December 31, 2003,2006, we had, for federal income tax purposes, operating loss carryforwards of approximately $58.4$21.3 million, expiring in the years 20182021 through 2022.2026.
S-16
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 65 — Stock Option and Stock Purchase Plans In May 2006, our shareholders approved the 2006 Long Term Incentive Plan (the “Plan”). The Plan provides for the issuance of up to 1,825,000 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 325,000 shares may be granted as restricted stock. No individual may be granted more than 900,000 options or SARs and no more than 175,000 shares of restricted stock during any period of three consecutive calendar years. 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 through December 31, 2006 will vest ratably over a three-year period from their dates of grant and expire ten years from grant date. Restricted stock granted to employees or consultants to date is subject to a restriction period of not less than 36 months during which the stock will be deposited with Harvest Natural Resources, Inc. and is subject to forfeiture under certain circumstances. Restricted stock granted to non-employee directors will vest as to one-third of the shares on each anniversary of the date of grant of the award provided that he is still a director on that date. 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. No employee or consultant shall be granted a performance award during a calendar year that could result in a cash payment of more than $5.0 million. 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 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
iswas 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 Non-qualifiedNon-Qualified Stock Options to eligible participants including employees of
S-17
our company or subsidiaries, directors, consultants and other key persons. The exercise price of stock options granted under the plan must be no less than the fair market value of our common stock on the date of grant. No officer may be granted more than 500,000 options during any one fiscal year, as adjusted for any changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.
Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 Long Term Stock Incentive Plan, no options may be granted under any of these plans.
A summary of the status of our stock option plans as of December 31, 2003, 20022006, 2005 and 20012004 and changes during the years ending on those dates is presented below (shares in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003
| | 2002
| | 2001
| | 2006 | | 2005 | | 2004 |
| | | Weighted | | Weighted | | Weighted | | Weighted | | Weighted | | Weighted |
| | | Average | | Average | | Average | | Average | | Average | | Average |
| | | Exercise
| | Exercise
| | Exercise
| | Exercise | | Exercise | | Exercise |
| | | Price
| | Shares
| | Price
| | Shares
| | Price
| | Shares
| | Price | | Shares | | Price | | Shares | | Price | | Shares |
| Outstanding at beginning of the year: | | $ | 7.42 | | 5,223 | | $ | 6.36 | | 6,865 | | 7.74 | | 5,660 | | | $ | 8.61 | | 4,070 | | $ | 8.18 | | 3,793 | | $ | 7.52 | | 4,523 | |
| Options granted | | 6.26 | | 246 | | 4.84 | | 165 | | 1.65 | | 1,684 | | | 10.62 | | 558 | | 11.51 | | 922 | | 13.36 | | 378 | |
| Options exercised | | 2.32 | | | (494 | ) | | 2.21 | | | (1,515 | ) | | — | | — | | | | (5.69 | ) | | | (65 | ) | | | (3.45 | ) | | | (241 | ) | | | (7.41 | ) | | | (955 | ) |
| Options cancelled | | 11.37 | | | (452 | ) | | 8.03 | | | (292 | ) | | 6.43 | | | (479 | ) | | | (19.96 | ) | | | (440 | ) | | | (14.24 | ) | | | (404 | ) | | | (6.31 | ) | | | (153 | ) |
| | |
| |
| |
| | | | | | | | |
| Outstanding at end of the year | | 7.52 | | 4,523 | | 7.42 | | 5,223 | | 6.36 | | 6,865 | | | 7.70 | | 4,123 | | 8.61 | | 4,070 | | 8.18 | | 3,793 | |
| | |
| |
| |
| | | | | | | | |
| Exercisable at end of the year | | 8.18 | | 3,857 | | 8.49 | | 4,360 | | 8.32 | | 4,800 | | | 5.91 | | 2,719 | | 7.40 | | 2,886 | | 7.71 | | 3,236 | |
| | |
| |
| |
| | | | | | | | |
Significant option groups outstanding at December 31, 20032006 and related weighted average price and life information follow:follow (shares in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Outstanding
| | Exercisable
|
| Range of | | Number | | Weighted-Average | | | | | | Number | | |
| Exercise | | Outstanding At | | Remaining | | Weighted-Average | | Exercisable at | | Weighted-Average |
Prices
| | December 31, 2003
| | Contractual Life
| | Exercise Price
| | December 31, 2003
| | Exercise Price
|
| $ | 1.55 | | | - | | $ | 2.75 | | | | 2,027,150 | | | | 5.91 | | | $ | 1.97 | | | | 1,679,983 | | | $ | 2.03 | |
| $ | 4.80 | | | - | | $ | 7.00 | | | | 621,000 | | | | 4.69 | | | | 5.81 | | | | 337,667 | | | | 5.87 | |
| $ | 7.25 | | | - | | $ | 11.00 | | | | 488,633 | | | | 1.69 | | | | 8.77 | | | | 452,633 | | | | 8.90 | |
| $ | 11.50 | | | - | | $ | 16.50 | | | | 946,665 | | | | 1.42 | | | | 13.52 | | | | 946,665 | | | | 13.52 | |
| $ | 17.38 | | | - | | $ | 24.13 | | | | 439,833 | | | | 1.78 | | | | 21.21 | | | | 439,833 | | | | 21.21 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | |
| | | | | | | | | | | | 4,523,281 | | | | | | | | | | | | 3,856,781 | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Outstanding | | | Exercisable | |
| | | | | | | Weighted- | | | | | | | | | | | | | | | | | | |
| | | | | | | Average | | | Weighted- | | | | | | | | | | | Weighted- | | | | |
| Range of | | Number | | | Remaining | | | Average | | | Aggregate | | | Number | | | Average | | | Aggregate | |
| Exercise | | Outstanding | | | Contractual | | | Exercise | | | Intrinsic | | | Exercisable | | | Exercise | | | Intrinsic | |
| Prices | | at 12/31/06 | | | Life | | | Price | | | Value | | | at 12/31/06 | | | Price | | | Value | |
| $ 1.55 - $ 2.75 | | | 1,486 | | | | 3.84 | | | $ | 1.97 | | | $ | 12,866 | | | | 1,486 | | | $ | 1.97 | | | $ | 12,866 | |
| $ 4.80 - $ 7.10 | | | 350 | | | | 5.61 | | | | 5.65 | | | | 1,744 | | | | 350 | | | | 5.65 | | | | 1,744 | |
| $ 8.72 - $10.91 | | | 1,121 | | | | 7.26 | | | | 10.08 | | | | 716 | | | | 159 | | | | 8.90 | | | | 275 | |
| $11.88 - $16.90 | | | 1,103 | | | | 5.40 | | | | 13.00 | | | | — | | | | 661 | | | | 12.92 | | | | — | |
| $18.25 - $19.75 | | | 63 | | | | 0.45 | | | | 19.04 | | | | — | | | | 63 | | | | 19.04 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 4,123 | | | | | | | | | | | $ | 15,326 | | | | 2,719 | | | | | | | $ | 14,885 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
The aggregate intrinsic value in the preceding table represents the total pretax intrinsic value based on our closing stock price of $10.63 as of December 31, 2006, which would have been received by the option holders had all option holders exercised their options as of that date. Of the number outstanding, 608,750 options are pledged to us to secure a repayment of debt.
The value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:
S-16S-18
Of
| | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| For options granted during: | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Weighted average fair value | | $ | 5.98 | | | $ | 6.35 | | | $ | 10.33 | |
| Weighted averaged expected life | | | 7 | | | | 7 | | | | 2-10 | |
| Valuation assumptions: | | | | | | | | | | | | |
| Expected volatility | | | 49.9%-53.3 | % | | | 50.0%-53.4 | % | | | 69.6 | % |
| Risk-free interest rate | | | 4.6%-5.2 | % | | | 3.9%-4.6 | % | | | 2.6%-4.8 | % |
| Expected dividend yield | | | 0 | % | | | 0 | % | | | 0 | % |
| Expected annual forfeitures | | | 3 | % | | | 3 | % | | | 0 | % |
The Black-Scholes option pricing model was developed for use in estimating the
number outstanding, 1,108,750value of traded options that have no vesting restrictions and are fully transferable. In addition, option pricing models require the input of highly subjective assumptions, including the expected stock price volatility and expected life. The expected volatility is based on historical volatilities of our stock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options are
controlled by us throughexpected to be outstanding. The risk-free rate for the
A. E. Benton settlement. SeeNote 13 – Related Party Transactions. In connection with our acquisitionperiods within the contractual life of Benton Offshore China Companythe option is based on the U.S. Treasury yield curve in December 1996, we adoptedeffect at the Benton Offshore China Company 1996 Stock Option Plan.time of grant. Under the plan, Benton Offshore China Company is authorized to issue up to 107,571Black-Scholes option pricing model, the weighted-average estimated values of stock 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,granted during 2006, 2005 and all options to purchase shares of Benton Offshore China Company common stock2004 were replaced under the plan by options to purchase shares$5.98, $6.35 and $10.33, respectively.
A summary of our common stock. All options were issued upon the acquisitionnonvested shares as of Benton Offshore China Company and vested upon issuance. At December 31, 2003, options2006, and changes during the year ended December 31, 2006, is presented below (shares in thousands):
| | | | | | | | | |
| | | | | | | Weighted-Average |
| | | | | | | Grant-Date |
| Nonvested Shares | | Shares | | Fair Value |
| Nonvested at January 1, 2006 | | | 1,185 | | | $ | 7.30 | |
| Granted | | | 557 | | | | 5.98 | |
| Vested | | | (328 | ) | | | 7.81 | |
| Forfeited | | | (10 | ) | | | 11.73 | |
| | | | | | | | | |
| Nonvested at December 31, 2006 | | | 1,404 | | | $ | 6.75 | |
| | | | | | | | | |
As of December 31, 2006, there was $5.8 million of total unrecognized compensation cost related to
purchase 74,427nonvested share-based compensation arrangements granted under our plans. That cost is expected to be recognized over the next three years. The total fair value of shares
of common stock were both outstandingvested during the years ended December 31, 2006, 2005 and
exercisable.2004 was $4.1 million, $2.7 million and $1.4 million, respectively.
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 $5.63 to $11.88 which vest over three
to four years. At December 31,
2003,2006, a total of
61,00010,000 options issued outside of the plans were both outstanding and exercisable.
Note 7 — Stock Warrants The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at December 31, 2003 were (warrants in thousands):
| | | | | | | | | | | | | | | |
| | | | | | | | | Warrants
|
Date Issued
| | Expiration Date
| | Exercise Price
| | Issued
| | Outstanding
|
| July 1994 | | July 2004 | | $ | 7.50 | | | | 150 | | | | 8 | |
| December 1994 | | December 2004 | | | 12.00 | | | | 50 | | | | 50 | |
| June 1995 | | June 2007 | | | 17.09 | | | | 125 | | | | 125 | |
| | | | | | | | | |
| | | |
| |
| | | | | | | | | | 325 | | | | 183 | |
| | | | | | | | | |
| | | |
| |
Note 86 — Operating Segments
We regularly allocate resources to and assess the performance of our operations by segments that are organized by unique geographic and operating characteristics. The segments are organized in order to manage regional business, currency and tax related risks and opportunities.
As a result of the situation in Venezuela, our GAAP consolidated financial statements for the nine months ended December 31, 2006 do not reflect the net results of our producing operations in Venezuela. SeeNote 7 – Venezuela, Operations. Revenue from Venezuela is derived primarily from the
productiondelivery and sale of oil and
natural gas.
Other income from USA and Other is derived primarily from interest earnings on various investments and consulting revenues. Operations included under the heading
“USA“United States and Other” include corporate management,
exploration activities, cash management,
business development and financing activities performed in the United States and other countries which do not meet the requirements for separate disclosure. All intersegment revenues, other income and equity earnings, expenses and receivables are eliminated in order to reconcile to consolidated totals. Corporate general and administrative and interest expenses are included in the
USAUnited States and Other segment and are not allocated to other operating segments.
S-17
Year ended December 31, 2003:
| | | | | | | | | | | | | | | | | | | | | |
(in thousands)
| | Venezuela
| | USA and Other
| | Russia
| | Eliminations
| | Consolidated
|
| Revenues | | | | | | | | | | | | | | | | | | | | |
| Oil sales | | $ | 103,920 | | | $ | — | | | $ | — | | | $ | — | | | $ | 103,920 | |
| Gas sales | | | 2,740 | | | | — | | | | — | | | | — | | | | 2,740 | |
| Ineffective hedge activity | | | (565 | ) | | | — | | | | — | | | | — | | | | (565 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | 106,095 | | | | — | | | | — | | | | — | | | | 106,095 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Expenses | | | | | | | | | | | | | | | | | | | | |
| Operating expenses | | | 31,309 | | | | 76 | | | | (492 | ) | | | — | | | | 30,893 | |
| Depletion, depreciation and amortization | | | 21,035 | | | | 109 | | | | 44 | | | | — | | | | 21,188 | |
| General and administrative | | | 4,031 | | | | 10,514 | | | | 1,201 | | | | — | | | | 15,746 | |
| Arbitration settlement | | | — | | | | 1,477 | | | | — | | | | — | | | | 1,477 | |
| Bad debt recovery | | | — | | | | (374 | ) | | | — | | | | — | | | | (374 | ) |
| Taxes other than on income | | | 2,921 | | | | 447 | | | | 5 | | | | — | | | | 3,373 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total expenses | | | 59,296 | | | | 12,249 | | | | 758 | | | | — | | | | 72,303 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Income (loss) from operations | | | 46,799 | | | | (12,249 | ) | | | (758 | ) | | | — | | | | 33,792 | |
| Other non-operating income (expense) | | | | | | | | | | | | | | | | | | | | |
| Gain on disposition of assets | | | — | | | | 46,619 | | | | — | | | | — | | | | 46,619 | |
| Investment earnings and other | | | 435 | | | | 983 | | | | — | | | | — | | | | 1,418 | |
| Interest expense | | | (1,944 | ) | | | (8,470 | ) | | | — | | | | 9 | | | | (10,405 | ) |
| Net gain on exchange rates | | | 495 | | | | 34 | | | | — | | | | — | | | | 529 | |
| Intersegment revenues (expenses) | | | (7,484 | ) | | | 7,484 | | | | — | | | | — | | | | — | |
| Equity in losses of affiliated companies | | | — | | | | — | | | | (28,860 | ) | | | — | | | | (28,860 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | (8,498 | ) | | | 46,650 | | | | (28,860 | ) | | | 9 | | | | 9,301 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Income (loss) before income taxes | | | 38,301 | | | | 34,401 | | | | (29,618 | ) | | | 9 | | | | 43,093 | |
| Income tax expense | | | 8,459 | | | | 1,187 | | | | 2 | | | | 9 | | | | 9,657 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Operating segment income (loss) | | | 29,842 | | | | 33,214 | | | | (29,620 | ) | | | — | | | | 33,436 | |
| Write-downs of oil and gas properties and impairments | | | — | | | | (165 | ) | | | — | | | | — | | | | (165 | ) |
| Minority interest | | | (5,968 | ) | | | — | | | | — | | | | — | | | | (5,968 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income (loss) | | $ | 23,874 | | | $ | 33,049 | | | $ | (29,620 | ) | | $ | — | | | $ | 27,303 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total assets | | $ | 241,855 | | | $ | 180,768 | | | $ | 237 | | | $ | (48,512 | ) | | $ | 374,348 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Additions to properties | | $ | 60,589 | | | $ | 245 | | | $ | 91 | | | $ | — | | | $ | 60,925 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Year ended December 31, 2002
| | | | | | | | | | | | | | | | | | | | | |
(in thousands)
| | Venezuela
| | USA and Other
| | Russia
| | Eliminations
| | Consolidated
|
| Revenues | | | | | | | | | | | | | | | | | | | | |
| Oil sales | | $ | 127,015 | | | $ | — | | | $ | — | | | $ | — | | | $ | 127,015 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Ineffective hedge activity | | | (284 | ) | | | — | | | | — | | | | — | | | | (284 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | 126,731 | | | | — | | | | — | | | | — | | | | 126,731 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Expenses | | | | | | | | | | | | | | | | | | | | |
| Operating expenses | | | 31,457 | | | | 360 | | | | 2,133 | | | | — | | | | 33,950 | |
| Depletion, depreciation and amortization | | | 23,850 | | | | 2,483 | | | | 30 | | | | — | | | | 26,363 | |
| General and administrative | | | 4,310 | | | | 11,420 | | | | 774 | | | | — | | | | 16,504 | |
| Bad debt recovery | | | — | | | | (3,276 | ) | | | — | | | | | | | | (3,276 | ) |
| Taxes other than on income | | | 3,997 | | | | 71 | | | | — | | | | — | | | | 4,068 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total expenses | | | 63,614 | | | | 11,058 | | | | 2,937 | | | | — | | | | 77,609 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Income (loss) from operations | | | 63,117 | | | | (11,058 | ) | | | (2,937 | ) | | | — | | | | 49,122 | |
| Other non-operating income (expense): | | | | | | | | | | | | | | | | | | | | |
| Gain on disposition of assets | | | — | | | | 144,032 | | | | (3 | ) | | | — | | | | 144,029 | |
| Gain on early extinguishment of debt | | | — | | | | 874 | | | | — | | | | — | | | | 874 | |
| Investment earnings and other | | | 1,889 | | | | 1,653 | | | | — | | | | (1,462 | ) | | | 2,080 | |
| Interest expense | | | (4,237 | ) | | | (13,611 | ) | | | — | | | | 1,538 | | | | (16,310 | ) |
| Net gain on exchange rates | | | 4,356 | | | | 197 | | | | — | | | | — | | | | 4,553 | |
| Intersegment revenues (expenses) | | | 15,156 | | | | (15,156 | ) | | | — | | | | — | | | | — | |
| Equity in income of affiliated companies | | | — | | | | — | | | | 165 | | | | — | | | | 165 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | 17,164 | | | | 117,989 | | | | 162 | | | | 76 | | | | 135,391 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Income (loss) before income taxes | | | 80,281 | | | | 106,931 | | | | (2,775 | ) | | | 76 | | | | 184,513 | |
| Income tax expense | | | 6,453 | | | | 53,764 | | | | 2 | | | | 76 | | | | 60,295 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Operating segment income (loss) | | | 73,828 | | | | 53,167 | | | | (2,777 | ) | | | — | | | | 124,218 | |
| Write-downs of oil and gas properties and impairments | | | — | | | | (14,537 | ) | | | — | | | | — | | | | (14,537 | ) |
| Minority interest | | | (9,319 | ) | | | — | | | | — | | | | — | | | | (9,319 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income (loss) | | $ | 64,509 | | | $ | 38,630 | | | $ | (2,777 | ) | | $ | — | | | $ | 100,362 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total assets | | $ | 209,733 | | | $ | 122,355 | | | $ | 52,302 | | | $ | (49,198 | ) | | $ | 335,192 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Additions to properties | | $ | 42,486 | | | | 738 | | | | 122 | | | | — | | | | 43,346 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
S-18
Year ended December 31, 2001:
| | | | | | | | | | | | | | | | | | | | | |
(in thousands)
| | Venezuela
| | USA and Other
| | Russia
| | Eliminations
| | Consolidated
|
| Revenues | | | | | | | | | | | | | | | | | | | | |
| Oil sales | | $ | 122,386 | | | $ | — | | | $ | — | | | $ | — | | | $ | 122,386 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Expenses | | | | | | | | | | | | | | | | | | | | |
| Operating expenses | | | 42,037 | | | | 55 | | | | 667 | | | | — | | | | 42,759 | |
| Depletion, depreciation and amortization | | | 22,096 | | | | 3,408 | | | | 12 | | | | — | | | | 25,516 | |
| General and administrative | | | 4,151 | | | | 14,972 | | | | 949 | | | | — | | | | 20,072 | |
| Taxes other than on income | | | 4,666 | | | | 704 | | | | — | | | | — | | | | 5,370 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total expenses | | | 72,950 | | | | 19,139 | | | | 1,628 | | | | — | | | | 93,717 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Income (loss) from operations | | | 49,436 | | | | (19,139 | ) | | | (1,628 | ) | | | — | | | | 28,669 | |
| Other non-operating income (expense): | | | | | | | | | | | | | | | | | | | | |
| Investment earnings and other | | | 5,995 | | | | 2,053 | | | | 60 | | | | (5,020 | ) | | | 3,088 | |
| Interest expense | | | (7,403 | ) | | | (22,695 | ) | | | — | | | | 5,223 | | | | (24,875 | ) |
| Net gain on exchange rates | | | 732 | | | | 36 | | | | — | | | | — | | | | 768 | |
| Intersegment revenues (expenses) | | | (14,983 | ) | | | 14,983 | | | | — | | | | — | | | | — | |
| Equity in income of affiliated companies | | | — | | | | — | | | | 5,902 | | | | — | | | | 5,902 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | (15,659 | ) | | | (5,623 | ) | | | 5,962 | | | | 203 | | | | (15,117 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Income (loss) before income taxes | | | 33,777 | | | | (24,762 | ) | | | 4,334 | | | | 203 | | | | 13,552 | |
| Income tax (benefit) expense | | | 6,491 | | | | (42,392 | ) | | | — | | | | 203 | | | | (35,698 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Operating segment income | | | 27,286 | | | | 17,630 | | | | 4,334 | | | | — | | | | 49,250 | |
| Write-down of oil and gas properties and impairments | | | — | | | | (468 | ) | | | — | | | | — | | | | (468 | ) |
| Minority interest | | | (5,545 | ) | | | — | | | | — | | | | — | | | | (5,545 | ) |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income | | $ | 21,741 | | | $ | 17,162 | | | | 4,334 | | | | — | | | $ | 43,237 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total assets | | $ | 167,671 | | | $ | 165,254 | | | $ | 100,801 | | | $ | (85,575 | ) | | $ | 348,151 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Additions to properties | | $ | 43,411 | | | $ | — | | | $ | 31 | | | $ | — | | | $ | 43,442 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
S-19
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (in thousands) | |
Segment Revenues | | | | | | | | | | | | |
| Oil and gas sales: | | | | | | | | | | | | |
| Venezuela | | $ | 59,506 | | | $ | 236,941 | | | $ | 186,066 | |
| | | | | | | | | | |
| Total oil and gas sales | | | 59,506 | | | | 236,941 | | | | 186,066 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Segment Income (Loss) | | | | | | | | | | | | |
| Venezuela | | | (42,895 | ) | | | 64,096 | | | | 54,469 | |
| United States and other | | | (15,667 | ) | | | (13,257 | ) | | | (20,109 | ) |
| | | | | | | | | | |
| Net income (loss) | | $ | (58,562 | ) | | $ | 50,839 | | | $ | 34,360 | |
| | | | | | | | | | |
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2006 | | | 2005 | |
| | | (in thousands) | |
Operating Segment Assets | | | | | | | | |
| Venezuela | | $ | 306,289 | | | $ | 258,268 | |
| United States and other | | | 155,973 | | | | 161,328 | |
| | | | | | | |
| | | | 462,262 | | | | 419,596 | |
| Intersegment eliminations | | | (39,551 | ) | | | (18,798 | ) |
| | | | | | | |
| | | $ | 422,711 | | | $ | 400,798 | |
| | | | | | | |
Note 9 - Russian7 — Venezuela OperationsGeoilbent
South Monagas Unit, Venezuela (Harvest Vinccler)
Currently, our only producing assets are in Venezuela. Since 1992, Harvest Vinccler has been providing operating services to PDVSA for the South Monagas Unit under an OSA. However, beginning in 2005, the government of Venezuela initiated a series of actions to compel companies with operating service agreements to convert those agreements into new companies in which PDVSA would have a majority interest. On September 25, 2003, we sold ourMarch 31, 2006, Harvest Vinccler signed a MOU with two affiliates of PDVSA, CVP and PPSA, to convert the OSA into a minority equity investmentinterest in GeoilbentPetrodelta. The MOU is subject to Yukos Operational Holding Limitedcertain conditions, including execution of a conversion contract, and Venezuelan government approvals. On August 16, 2006, the MOU was amended to provide for $69.5 million plus the repaymentaddition of the subordinated loanIsleño, El Salto and certain payables owedTemblador fields to usPetrodelta as additional consideration for our conversion of the OSA to Petrodelta. On December 18, 2006, at a Special Meeting of the Stockholders, the transactions contemplated by Geoilbent in the amountMOU were approved. As of $5.5 million. Priorthis report, the governmental approvals necessary to complete the conversion have not yet been obtained, and the timing of and probability for such approval is uncertain.
In April 2006, the Venezuelan National Assembly passed legislation terminating all operating service agreements and directing the government to take over the operations carried out by the private companies without prejudice to the
sale, we owned 34 percentincorporation of
Geoilbent,mixed companies for that purpose. This action, coupled with the unfinished conversion to Petrodelta, has left Harvest Vinccler without a
Russian limited liability company, formed in 1991contractual means recognized by the government of Venezuela to
develop, produceaddress revenues or costs 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 years ended September 30, 2002 and 2001 were 5.6 million barrels (3.3 million domestic and 2.3 million export), 6.9 million barrels (4.6 million domestic and 2.3 million export) and 5.2 million barrels (0.8 million domestic and 4.4 million export), respectively. Prices for crude oil for the period until it was sold on September 25, 2003 and for the years ended September 30, 2002 and 2001 averaged $14.52 ($8.61 domestic and $23.05 export), $13.25 ($8.89 domestic and $21.73 export) and $19.51 ($13.69 domestic and $20.48 export) per barrel, respectively. Depletion expense attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the years ended September 30, 2002 and 2001 was $3.23, $3.93 and $2.88 per barrel, respectively. All amounts represent 100 percent of Geoilbent. Summarized financial information for Geoilbent follows (in thousands):| | | | | | | | | | | | | |
| | | 2003
| | 2002
| | 2001
|
Year ended September 30: | | | | | | | | | | | | |
| Revenues | | | | | | | | | | | | |
| Oil sales | | $ | 81,724 | | | $ | 91,598 | | | $ | 101,159 | |
| | | |
| | | |
| | | |
| |
| Expenses | | | | | | | | | | | | |
| Selling and distribution expenses | | | 5,893 | | | | 6,696 | | | | 9,876 | |
| Operating expenses | | | 15,897 | | | | 15,360 | | | | 11,415 | |
| Depletion, depreciation and amortization | | | 18,182 | | | | 27,168 | | | | 14,918 | |
| Write-downs of oil and gas properties | | | 95,000 | | | | — | | | | — | |
| General and administrative | | | 9,456 | | | | 8,335 | | | | 5,650 | |
| Taxes other than on income | | | 25,626 | | | | 27,657 | | | | 26,011 | |
| | | |
| | | |
| | | |
| |
| | | | 170,054 | | | | 85,216 | | | | 67,870 | |
| | | |
| | | |
| | | |
| |
| Income (loss) from operations | | | (88,330 | ) | | | 6,382 | | | | 33,289 | |
| Other non-operating income (expense) | | | | | | | | | | | | |
| Investment earnings and other | | | 1,064 | | | | 381 | | | | 648 | |
| Interest expense | | | (1,992 | ) | | | (4,629 | ) | | | (7,547 | ) |
| Net gain on exchange rates | | | 1,566 | | | | 2,053 | | | | 781 | |
| | | |
| | | |
| | | |
| |
| | | | 638 | | | | (2,195 | ) | | | (6,118 | ) |
| | | |
| | | |
| | | |
| |
| Income (loss) before income taxes | | | (87,692 | ) | | | 4,187 | | | | 27,171 | |
| Income tax expense | | | (3,117 | ) | | | 302 | | | | 6,751 | |
| | | |
| | | |
| | | |
| |
| | | | (84,575 | ) | | | 3,885 | | | | 20,420 | |
| Effects of change in accounting policy | | | 310 | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Net income (loss) | | $ | (84,885 | ) | | $ | 3,885 | | | $ | 20,420 | |
| | | |
| | | |
| | | |
| |
At September 30: | | | | | | | | | | | | |
| Current assets | | | | | | $ | 18,785 | | | $ | 35,447 | |
| Other assets | | | | | | | 186,815 | | | | 187,706 | |
| Current liabilities | | | | | | | 54,051 | | | | 60,439 | |
| Other liabilities | | | | | | | 7,500 | | | | 22,550 | |
| Net equity | | | | | | | 144,049 | | | | 140,164 | |
As of September 30, 2002, the Geoilbent shareholders had provided Geoilbent with subordinate loans totaling $7.5 million ($2.5 million from us). These loans were unsecured, repayable in January 2004 and recorded as a current liability at September 30, 2003. The loan by us was repaid as part of the sale of our minority equity investment in Geoilbent. As of January 1, 2003, the Russian economy was no longer a highly inflationary economy.expenses since March 31, 2006. As a result the Russian Ruble became the functional currency and not the U.S. dollar.
S-20
Arctic Gas Company
On April 12, 2002, we soldof this situation, our 68 percent equity interestconsolidated financial statements prepared 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,accordance with GAAP for the year ended December 31, 2001 was 39 percent.2006, do not reflect the net results of our producing operations in Venezuela for the last three quarters of the year. We recordedwill not be able to include the results of our Venezuelan operations in our consolidated financial statements until the conversion to Petrodelta is completed. Although the MOU provides that upon completion of the conversion, there will be an adjustment between the parties to obtain the same economic result as our shareif the conversion had been completed on April 1, 2006, this adjustment will not occur until the conversion is completed.
Since signing the MOU, CVP has designated its board members and a General Manager and President for Petrodelta, both of whom influence Harvest Vinccler’s operations and staffing. Harvest Vinccler continues in the
lossesday-to-day operations of
Arctic Gas $1.5its properties in Venezuela, and during the last three quarters of 2006, it has accrued cash advances of $36.3 million
to fund operations. At the request of PDVSA, Harvest Vinccler invoiced PDVSA for these costs and
$1.1$21.2 million,
representing the second and third quarter advances, have been reimbursed. Harvest Vinccler invoiced PDVSA for fourth quarter advances of $15.1 million in February 2007. In 2006, Harvest Vinccler resolved and substantially paid all of the tax claims made by the SENIAT. Harvest Vinccler paid $73.8S-20
million additional taxes and related interest for the period ended April 12, 2002 and September 30,periods of 2001 respectively. Summarized financial informationthrough first quarter 2006. The tax payments were largely made through borrowings by Harvest Vinccler, which are partially collateralized with restricted cash deposits.
At December 31, 2006, Harvest Vinccler has three loans outstanding with two Venezuelan banks for
Arctic Gas follows (in thousands)a total of 225 billion Bolivars (approximately $104.7 million).
All amounts represent 100 percent of Arctic Gas.| | | | | | | | | |
| | | 2002
| | 2001
|
Year ended September 30: | | | | | | | | |
| Revenues | | | | | | | | |
| Oil Sales | | $ | 7,880 | | | $ | 13,374 | |
| | | |
| | | |
| |
| Expenses | | | | | | | | |
| Selling and distribution expenses | | | 3,170 | | | | 3,867 | |
| Operating expense | | | 2,473 | | | | 3,483 | |
| Depletion, depreciation and amortization | | | 333 | | | | 1,032 | |
| General and administrative | | | 2,112 | | | | 3,025 | |
| Taxes other than on income | | | 1,261 | | | | 3,881 | |
| | | |
| | | |
| |
| | | | 9,349 | | | | 15,288 | |
| | | |
| | | |
| |
| Loss from operations | | | (1,469 | ) | | | (1,914 | ) |
| Other non-operating income (expense) | | | | | | | | |
| Other income (expense) | | | (4 | ) | | | 54 | |
| Interest and foreign exchange expense | | | (1,722 | ) | | | (1,848 | ) |
| | | |
| | | |
| |
| | | | (1,726 | ) | | | (1,794 | ) |
| | | |
| | | |
| |
| Loss before income taxes | | | (3,195 | ) | | | (3,708 | ) |
| Income tax expense | | | — | | | | — | |
| | | |
| | | |
| |
| Net loss | | $ | (3,195 | ) | | $ | (3,708 | ) |
| | | |
| | | |
| |
Note 10 - Venezuela Operations
On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then one of three exploration and production affiliates of the national oil company, PDVSA.These loans are collateralized by $88.9 million deposited in two U.S. banks. 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, Benton-Vinccler, a Venezuelan corporation owned 80 percent by us and 20 percent by Vinccler, is a contractor for PDVSA and is responsible for overall operations of the South Monagas Unit, including all necessary investments to reactivate and develop the fields comprising the South Monagas Unit. Benton-Vinccler receives an operating fee in U.S. dollars deposited into a U.S. commercial bank account for each barrel of crude oil produced (subject to periodic adjustments to reflect changes in a special energy index of the U.S. Consumer Price Index) and is reimbursed according to a prescribed formula in U.S. dollars for its capital costs, provided that such operating fee and cost recovery fee cannot exceed the maximum dollar amount per barrel set forth in the agreement.
In September 2002, Benton-Vinccler and PDVSA signed an amendment to the operating service agreement, providing for the delivery of up to 198 Bcf of natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales commenced in the fourth quarter of 2003. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production at $7.00 per barrel beginning with our first gas sale. Initial gas production will come from Uracoa, which allows us to more efficiently manage the reservoir and eliminate the restrictions on producing oil wells with high gas to oil ratios. The gas reserves in Bombal will beloans were used to meet the future termsSENIAT income tax assessments and related interest, refinance a portion of one of the gas contract in 2005.
S-21
The Venezuelan government maintains full ownership of all hydrocarbons in the fields.
We drilled three oil wellsBolivar loans and converted two gas injection wells to producing wells in 2003.
fund operating requirements.
Note 11 - United States Operations 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. All capitalized costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the onshore property for sale.
Note 12 -8 — China Operations
In December 1996, we acquired Crestone Energy Corporation, subsequently renamed Benton Offshore China Company. Its principal asset is a petroleum contract with China National Offshore Oil Corporation (“CNOOC”) 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
territorialborder 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
territorialborder dispute has lasted for many years, and there has been limited exploration and no development activity in the
WAB-21 area
underdue to the dispute.
As part of a review of our assets, a third-party conductedDue to the border dispute between China and Vietnam, we have been unable to pursue an
evaluationexploration program during Phase One of the
WAB-21 area. Through that evaluation and our own assessmentcontract. As a result, we
recorded a $13.4 million impairment chargehave obtained license extensions, with the current extension in
effect until May 31, 2007. While no assurance can be given, we believe we will continue to receive contract extensions so long as the
second quarter of 2002. An evaluation was performed again at December 31, 2003 and such evaluation indicated that no further impairment of the property had been incurred in 2003.border disputes persist. WAB-21 represents the $2.9 million excluded from the full cost pool as reflected on our December 31,
20032006 balance sheet.
Note 13 -9 — Related Party Transactions We have entered into construction service agreements with Venezolana International, S.A. (“Vinsa”). Vinsa is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Benton-Vinccler. Vinsa has provided $1.7 million, $0.5 million and $0.6 million in construction services on our Venezuelan gas pipeline and field operations for the years ended December 31, 2003, 2002 and 2001, respectively.
We have
In August 1997, we entered into a consulting agreement with Oil & Gas Technology Consultants Inc. (“OGTC”) to provide operational and technical assistance in Venezuela. OGTC is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which
indirectly owns 20 percent of
Benton-Vinccler.Harvest Vinccler. Payment for services is due when earnings are not reinvested in
Benton-VincclerHarvest Vinccler operations.
Expenses related to thisThe consulting agreement was
$1.5 million, $2.6cancelled January 1, 2004. At December 31, 2006 and 2005, we owed $9.6 million and
$2.5$9.2 million,
at December 31, 2003, 2002 and 2001, respectively. From 1996 through 1998, we made unsecured loans to our then Chief Executive Officer, A. E. Benton, bearing interest at the rate of 6 percent per annum. We subsequently obtained a security interest in Mr. Benton’s shares of our stock and stock options. In August 1999, Mr. Benton filed a chapter 11 (reorganization) bankruptcy petition in the U.S. Bankruptcy Court for the Central District of California, in Santa Barbara, California. In February 2000, we entered into a separation agreement with Mr. Benton pursuant to which we retained Mr. Bentonrespectively, under a consulting agreement to perform certain services for us. In addition, the consulting agreement provided Mr. Benton with incentive bonuses tied to our net cash receipts from the sale of our interests in Arctic Gas and Geoilbent. In June 2002, we made an incentive bonus payment to Mr. Benton of $1.5 million, subject to future adjustment, in connection with the Arctic Gas sale. We recorded the bonus payment as a reduction of the gain on the Arctic Gas sale. In November 2003, we made a payment to Mr. Benton of $0.5 million for the incentive bonus associated with the sale of our minority equity investment in Geoilbent.
In May 2001, we and Mr. Benton entered into a settlement and release agreement under which the consulting agreement was terminated as to future services and Mr. Benton agreed to propose a plan of reorganization in his bankruptcy case that provided for the repayment of our loans to him. In March 2002, Mr. Benton filed a plan of reorganization, and on July 31, 2002, the bankruptcy court confirmed the plan of reorganization. At the time the plan became final, Mr. Benton’s indebtedness to us was about $6.7 million for which we provided a full allowance for bad debt. On August 14, 2002, we exercised our rights with respect to 600,000 shares of our stock pledged to us as partial repayment of the loan and took the shares into our treasury stock. Based on a $3.56 closing price for the stock on that date, the value of the shares was $2.1 million. Also, in September 2002 and July 2003, we received payments of approximately $1.3 million as distributions from Mr.
S-22
agreement.
Benton’s debtor-in-possession account. Finally, under the terms of the settlement agreement, we have retained about $0.2 million from the Arctic Gas and Geoilbent bonus payments to Mr. Benton, bringing the total recovery on Mr. Benton’s debt to $3.7 million. We continue to accrue interest and provide a bad debt allowance on the remaining amount due. In addition, we hold the rights to direct the exercise of Mr. Benton’s stock options.
We and Mr. Benton disagreed over Mr. Benton’s remaining obligations to us under the settlement agreement and plan of reorganization. In addition, Mr. Benton claimed that he was due significant additional amounts with respect to the incentive bonus associated with the Arctic Gas sale. We and Mr. Benton submitted our dispute to binding arbitration and in October 2003 the arbitrator found in favor of Mr. Benton in all material respects. As a result, in October 2003, we made a payment to Mr. Benton of $1.9 million for the balance of the incentive bonus associated with the Arctic Gas sale and released certain funds for the payment of Mr. Benton’s taxes and expenses related to the disposition of his 600,000 shares of stock.
Note 14 -10 — Earnings Per Share
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
35.337.2 million,
34.636.9 million and
33.936.1 million for the years ended December 31,
2003, 20022006, 2005 and
2001,2004, respectively. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was
36.837.2 million,
36.138.4 million and
34.038.1 million for the years ended December 31,
2003, 20022006, 2005 and
2001,2004, respectively.
An aggregate of 2.51.5 million options and warrants were excluded from the earnings per share calculations because they were anti-dilutivetheir exercise price exceeded the average price for the year ended December 31, 2003.2006. For the years ended December 31, 20022005 and 2001, 3.52004, 1.9 million and 6.70.9 million options and warrants, respectively, were excluded from the earnings per share calculations because they were anti-dilutive.their exercise price exceeded the average price.
Note 11 – Subsequent Event
On January 19, 2007, we purchased a 45 percent interest in Fusion Geophysical, L.L.C. (“Fusion”) for $4.6 million. Fusion is a technical firm specializing in the areas of geophysics, geosciences and reservoir engineering.
S-23S-21
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES Quarterly Financial Data (unaudited) Summarized quarterly financial data is as follows:
| | | | | | | | | | | | | | | | | |
| | | Quarter Ended
|
| | | March 31
| | June 30
| | September 30
| | December 31
|
| | | (amounts in thousands, except per share data) |
Year ended December 31, 2003 | | | | | | | | | | | | | | | | |
| Revenues | | $ | 18,825 | | | $ | 28,576 | | | $ | 27,834 | | | $ | 30,860 | |
| Expenses | | | (13,901 | ) | | | (19,911 | ) | | | (20,037 | ) | | | (18,619 | ) |
| Non-operating income (expense) | | | (1,864 | ) | | | (2,288 | ) | | | 44,056 | | | | (1,743 | ) |
| | | |
| | | |
| | | |
| | | |
| |
| Income from consolidated companies before income taxes and minority interests | | | 3,060 | | | | 6,377 | | | | 51,853 | | | | 10,498 | |
| Income tax expense | | | 1,056 | | | | 3,104 | | | | 3,603 | | | | 1,894 | |
| | | |
| | | |
| | | |
| | | |
| |
| Income before minority interests | | | 2,004 | | | | 3,273 | | | | 48,250 | | | | 8,604 | |
| Minority interests | | | 887 | | | | 1,216 | | | | 1,367 | | | | 2,498 | |
| | | |
| | | |
| | | |
| | | |
| |
| Income from consolidated companies | | | 1,117 | | | | 2,057 | | | | 46,883 | | | | 6,106 | |
| Equity in net income (losses) of affiliated companies | | | (16,575 | ) | | | (13,470 | ) | | | (473 | ) | | | 1,658 | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income (loss) | | $ | (15,458 | ) | | $ | (11,413 | ) | | $ | 46,410 | | | $ | 7,764 | |
| Other comprehensive income (loss) | | | 2,614 | | | | (3,001 | ) | | | 21 | | | | 366 | |
| | | |
| | | |
| | | |
| | | |
| |
| Total comprehensive income (loss) | | $ | (12,844 | ) | | $ | (14,414 | ) | | $ | 46,431 | | | $ | 8,130 | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income (loss) per common share: | | | | | | | | | | | | | | | | |
| Basic | | $ | (0.44 | ) | | $ | (0.32 | ) | | $ | 1.31 | | | $ | 0.22 | |
| | | |
| | | |
| | | |
| | | |
| |
| Diluted | | $ | (0.44 | ) | | $ | (0.32 | ) | | $ | 1.25 | | | $ | 0.21 | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | | | | | | | | | | | | | | |
| | | Quarter Ended
|
| | | March 31
| | June 30
| | September 30
| | December 31
|
| | | (amounts in thousands, except per share data) |
Year ended December 31, 2002 | | | | | | | | | | | | | | | | |
| Revenues | | $ | 27,247 | | | $ | 33,022 | | | $ | 38,841 | | | $ | 27,621 | |
| Expenses | | | (18,720 | ) | | | (35,747 | ) | | | (17,914 | ) | | | (19,765 | ) |
| Non-operating income (expense) | | | (3,948 | ) | | | 142,940 | | | | (818 | ) | | | (2,948 | ) |
| | | |
| | | |
| | | |
| | | |
| |
| Income from consolidated companies before income taxes and minority interests | | | 4,579 | | | | 140,215 | | | | 20,109 | | | | 4,908 | |
| Income tax expense (benefit) | | | 1,801 | | | | 59,692 | | | | 6,612 | | | | (7,810 | ) |
| | | |
| | | |
| | | |
| | | |
| |
| Income before minority interests | | | 2,778 | | | | 80,523 | | | | 13,497 | | | | 12,718 | |
| Minority interests | | | 1,380 | | | | 2,031 | | | | 2,590 | | | | 3,318 | |
| | | |
| | | |
| | | |
| | | |
| |
| Income from consolidated companies | | | 1,398 | | | | 78,492 | | | | 10,907 | | | | 9,400 | |
| Equity in net income (losses) of affiliated companies | | | 87 | | | | (2,172 | ) | | | 1,209 | | | | 1,041 | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income | | $ | 1,485 | | | $ | 76,320 | | | $ | 12,116 | | | $ | 10,441 | |
| | | |
| | | |
| | | |
| | | |
| |
| Other comprehensive loss | | | — | | | | — | | | | (658 | ) | | | 658 | |
| | | |
| | | |
| | | |
| | | |
| |
| Total comprehensive income | | | 1,485 | | | | 76,320 | | | | 11,458 | | | | 11,099 | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income per common share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.04 | | | $ | 2.20 | | | $ | 0.35 | | | $ | 0.30 | |
| | | |
| | | |
| | | |
| | | |
| |
| Diluted | | $ | 0.04 | | | $ | 2.10 | | | $ | 0.33 | | | $ | 0.28 | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | | | | | | | | | | | | | | |
| | | Quarter Ended | |
| | | March 31 | | | June 30 | | | September 30 | | | December 31 | |
| | | (amounts in thousands, except per share data) | |
Year ended December 31, 2006 | | | | | | | | | | | | | | | | |
| Revenues | | $ | 59,172 | | | $ | 334 | | | $ | — | | | $ | — | |
| Expenses | | | (28,143 | ) | | | (7,796 | ) | | | (7,654 | ) | | | (10,414 | ) |
| Non-operating income (expense) | | | 1,940 | | | | (13,419 | ) | | | (2,650 | ) | | | 258 | |
| | | | | | | | | | | | | |
| Income before income taxes and minority interests | | | 32,969 | | | | (20,881 | ) | | | (10,304 | ) | | | (10,156 | ) |
| Income tax expense | | | 14,762 | | | | 40,810 | | | | 5,338 | | | | 7 | |
| | | | | | | | | | | | | |
| Income before minority interests | | | 18,207 | | | | (61,691 | ) | | | (15,642 | ) | | | (10,163 | ) |
| Minority interests | | | 4,339 | | | | (11,409 | ) | | | (2,044 | ) | | | (1,613 | ) |
| | | | | | | | | | | | | |
| Net income (loss) | | $ | 13,868 | | | $ | (50,282 | ) | | $ | (13,598 | ) | | $ | (8,550 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Net income (loss) per common share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.37 | | | $ | (1.35 | ) | | $ | (0.36 | ) | | $ | (0.23 | ) |
| | | | | | | | | | | | | |
| Diluted | | $ | 0.36 | | | $ | (1.35 | ) | | $ | (0.36 | ) | | $ | (0.23 | ) |
| | | | | | | | | | | | | |
In the second quarter of 2002, we recognized in non-operating income, the $144.0 million pre-tax gain on the Arctic Gas Sale, and in expense, the write-down of capitalized costs of $13.4 million associated with our WAB-21 offshore China concession.
S-24
| | | | | | | | | | | | | | | | | |
| | | Quarter Ended | |
| | | March 31 | | | June 30 | | | September 30 | | | December 31 | |
| | | (amounts in thousands, except per share data) | |
Year ended December 31, 2005 | | | | | | | | | | | | | | | | |
| Revenues | | $ | 60,986 | | | $ | 56,442 | | | $ | 61,221 | | | $ | 58,292 | |
| Expenses | | | (27,300 | ) | | | (26,207 | ) | | | (32,245 | ) | | | (31,664 | ) |
| Non-operating income (expense) | | | 3,054 | | | | 277 | | | | (1,827 | ) | | | 2,065 | |
| | | | | | | | | | | | | |
| Income before income taxes and minority interests | | | 36,740 | | | | 30,512 | | | | 27,149 | | | | 28,693 | |
| Income tax expense | | | 13,533 | | | | 11,959 | | | | 16,332 | | | | 15,201 | |
| | | | | | | | | | | | | |
| Income before minority interests | | | 23,207 | | | | 18,553 | | | | 10,817 | | | | 13,492 | |
| Minority interests | | | 5,172 | | | | 4,402 | | | | 2,674 | | | | 2,982 | |
| | | | | | | | | | | | | |
| Net income | | $ | 18,035 | | | $ | 14,151 | | | $ | 8,143 | | | $ | 10,510 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Net income per common share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.49 | | | $ | 0.38 | | | $ | 0.22 | | | $ | 0.28 | |
| | | | | | | | | | | | | |
| Diluted | | $ | 0.47 | | | $ | 0.37 | | | $ | 0.21 | | | $ | 0.27 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Other comprehensive income (loss) | | | (6,048 | ) | | | 1,770 | | | | 2,287 | | | | 1,991 | |
| | | | | | | | | | | | | |
| Total comprehensive income | | $ | 11,987 | | | $ | 15,921 | | | $ | 10,430 | | | $ | 12,501 | |
| | | | | | | | | | | | | |
Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
The following tables summarize our proved reserves, drilling and production activity, and financial operating data at the end of each year. The Venezuelan reserves are attributable to our OSA between Harvest Vinccler and Petroleos de Venezuela S.A. under which all mineral rights are owned by the government of Venezuela. The government of Venezuela unilaterally terminated the OSA in April 2006.
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-22
TABLE I -— Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | United States | | | | Venezuela | | China | | Total | |
| | | Venezuela
| | China
| | and Other
| | Total
| |
Year Ended December 31, 2003 | | |
Year Ended December 31, 2006 | | |
| Development costs | | $ | 58,079 | | $ | — | | $ | 2 | | $ | 58,081 | | | $ | 501 | | $ | — | | $ | 501 | |
| Exploration costs | | 11 | | 39 | | 133 | | 183 | | | — | | 35 | | 35 | |
| | |
| |
| |
| |
| | | | | | | | |
| | | $ | 58,090 | | $ | 39 | | $ | 135 | | $ | 58,264 | | | $ | 501 | | $ | 35 | | $ | 536 | |
| | |
| |
| |
| |
| | | | | | | | |
Year Ended December 31, 2002 | | |
| | | |
Year Ended December 31, 2005 | | |
| Development costs | | $ | 49,163 | | $ | 120 | | $ | 577 | | $ | 49,860 | | | $ | 8,912 | | $ | — | | $ | 8,912 | |
| Exploration costs | | 794 | | | (149 | ) | | 88 | | 733 | | | — | | 42 | | 42 | |
| | |
| |
| |
| |
| | | | | | | | |
| | | $ | 49,957 | | $ | (29 | ) | | $ | 665 | | $ | 50,593 | | | $ | 8,912 | | $ | 42 | | $ | 8,954 | |
| | |
| |
| |
| |
| | | | | | | | |
Year Ended December 31, 2001 | | |
| Acquisition costs | | $ | | $ | | $ | | $ | | |
| | | |
Year Ended December 31, 2004 | | |
| Development costs | | 35,194 | | 77 | | 28 | | 35,299 | | | $ | 39,161 | | $ | — | | $ | 39,161 | |
| Exploration costs | | 7,694 | | — | | 909 | | 8,603 | | | 10 | | 53 | | 63 | |
| | |
| |
| |
| |
| | | | | | | | |
| | | $ | 42,888 | | $ | 77 | | $ | 937 | | $ | 43,902 | | | $ | 39,171 | | $ | 53 | | $ | 39,224 | |
| | |
| |
| |
| |
| | | | | | | | |
TABLE II -— Capitalized costs related to oil and natural gas producing activities (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | United States | | | | Venezuela(a) | | China(b) | | Total | |
| | | Venezuela
| | China
| | and Other
| | Total
| |
December 31, 2003 | | |
Year Ended December 31, 2006 | | |
| Proved property costs | | $ | 569,055 | | $ | 13,401 | | $ | — | | $ | 582,456 | | | $ | — | | $ | 13,532 | | $ | 13,532 | |
| Costs excluded from amortization | | — | | 2,900 | | — | | 2,900 | | | — | | 2,900 | | 2,900 | |
| Oilfield inventories | | 8,266 | | — | | — | | 8,266 | | | — | | — | | — | |
| Less accumulated depletion and impairment | | | (398,206 | ) | | | (13,401 | ) | | — | | | (411,607 | ) | | — | | | (13,532 | ) | | | (13,532 | ) |
| | |
| |
| |
| |
| | | | | | | | |
| | | $ | 179,115 | | $ | 2,900 | | $ | — | | $ | 182,015 | | | $ | — | | $ | 2,900 | | $ | 2,900 | |
| | |
| |
| |
| |
| | | | | | | | |
December 31, 2002 | | |
| | | |
Year Ended December 31, 2005 | | |
| Proved property costs | | $ | 519,175 | | $ | 26,210 | | $ | 21,030 | | $ | 566,415 | | | $ | 617,137 | | $ | 13,497 | | $ | 630,634 | |
| Costs excluded from amortization | | — | | 2,900 | | — | | 2,900 | | | — | | 2,900 | | 2,900 | |
| Oilfield inventories | | 7,286 | | — | | — | | 7,286 | | | 8,150 | | — | | 8,150 | |
| Less accumulated depletion and impairment | | | (386,824 | ) | | | (26,210 | ) | | | (20,764 | ) | | | (433,798 | ) | | | (473,496 | ) | | | (13,497 | ) | | | (486,993 | ) |
| | |
| |
| |
| |
| | | | | | | | |
| | | $ | 139,637 | | $ | 2,900 | | $ | 266 | | $ | 142,803 | | | $ | 151,791 | | $ | 2,900 | | $ | 154,691 | |
| | |
| |
| |
| |
| | | | | | | | |
December 31, 2001 | | |
| | | |
Year Ended December 31, 2004 | | |
| Proved property costs | | $ | 469,218 | | $ | 12,892 | | $ | 19,813 | | $ | 501,923 | | | $ | 608,225 | | $ | 13,454 | | $ | 621,679 | |
| Costs excluded from amortization | | — | | 16,248 | | 560 | | 16,808 | | | — | | 2,900 | | 2,900 | |
| Oilfield inventories | | 15,219 | | — | | — | | 15,219 | | | 6,503 | | — | | 6,503 | |
| Less accumulated depletion and impairment | | | (361,313 | ) | | | (12,892 | ) | | | (19,544 | ) | | | (393,749 | ) | | | (432,302 | ) | | | (13,454 | ) | | | (445,756 | ) |
| | |
| |
| |
| |
| | | | | | | | |
| | | $ | 123,124 | | $ | 16,248 | | $ | 829 | | $ | 140,201 | | | $ | 182,426 | | $ | 2,900 | | $ | 185,326 | |
| | |
| |
| |
| |
| | | | | | | | |
| | |
| (a) | | Reclassified to provisional equity affiliate effective April 1, 2006.
|
|
| (b) | | SeeNotes to the Consolidated Financial Statements Note 8 – China Operations. |
S-25S-23
TABLE III -— Results of operations for oil and natural gas producing activities (in thousands):
| | | | | | | | | | | | | | | | | |
| | | United States | | | | Venezuela | |
| | | Venezuela
| | China
| | and Other
| | Total
| |
Year ended December 31, 2003 | | |
| Oil sales | | $ | 106,095 | | $ | — | | $ | — | | $ | 106,095 | | |
Year ended December 31, 2006(a) | | |
| Oil and natural gas revenues | | | $ | 59,506 | |
| Expenses: | | |
| Operating, selling and distribution expenses and taxes other than on income | | 31,445 | | — | | 76 | | 31,521 | | | 9,451 | |
| Write-down of oil and gas properties and impairments | | — | | 23 | | 142 | | 165 | | |
| Depletion | | | 9,904 | |
| Income tax expense | | | 20,076 | |
| | | | | |
Total expenses(b) | | | 39,431 | |
| | | | | |
| Results of operations from oil and natural gas producing activities | | | $ | 20,075 | |
| | | | | |
| | | |
Year ended December 31, 2005 | | |
| Oil and natural gas revenues | | | $ | 236,941 | |
| Expenses: | | |
| Operating, selling and distribution expenses and taxes other than on income | | | 39,969 | |
| Depletion | | 19,599 | | — | | — | | 19,599 | | | 41,175 | |
| Income tax expense | | 12,158 | | — | | 1,187 | | 13,345 | | | 65,943 | |
| | |
| |
| |
| |
| | | | |
| Total expenses | | 63,202 | | 23 | | 1,405 | | 64,630 | | | 147,087 | |
| | |
| |
| |
| |
| | | | |
| Results of operations from oil and natural gas producing activities | | $ | 42,893 | | $ | (23 | ) | | $ | (1,405 | ) | | $ | 41,465 | | | $ | 89,854 | |
| | |
| |
| |
| |
| | | | |
Year ended December 31, 2002 | | |
| Oil sales | | $ | 126,731 | | $ | — | | $ | — | | $ | 126,731 | | |
| | | |
Year ended December 31, 2004 | | |
| Oil and natural gas revenues | | | $ | 186,066 | |
| Expenses: | | |
| Operating, selling and distribution expenses and taxes other than on income | | 31,608 | | 2,493 | | — | | 34,101 | | | 33,297 | |
| Write-down of oil and gas properties and impairments | | — | | 13,371 | | 1,166 | | 14,537 | | |
| Depletion | | 24,941 | | — | | — | | 24,941 | | | 34,108 | |
| Income tax expense | | 4,715 | | 3 | | — | | 4,718 | | | 38,968 | |
| | |
| |
| |
| |
| | | | |
| Total expenses | | 61,264 | | 15,867 | | 1,166 | | 78,297 | | | 106,373 | |
| | |
| |
| |
| |
| | | | |
| Results of operations from oil and natural gas producing activities | | $ | 65,467 | | $ | (15,867 | ) | | | (1,166 | ) | | 48,434 | | | $ | 79,693 | |
| | |
| |
| |
| |
| | | | |
Year ended December 31, 2001 | | |
| Oil and natural gas sales | | $ | 122,386 | | $ | — | | $ | — | | $ | 122,386 | | |
| Expenses: | | |
| Operating, selling and distribution expenses and taxes other than on income | | 42,212 | | — | | 722 | | 42,934 | | |
| Write-down of oil and gas properties and impairments | | — | | 13 | | 455 | | 468 | | |
| Depletion | | 22,119 | | — | | — | | 22,119 | | |
| Income tax expense | | 11,156 | | — | | 13 | | 11,169 | | |
| | |
| |
| |
| |
| | |
| Total expenses | | 75,487 | | 13 | | 1,190 | | 76,690 | | |
| | |
| |
| |
| |
| | |
| Results of operations from oil and natural gas producing activities | | $ | 46,899 | | $ | (13 | ) | | $ | (1,190 | ) | | $ | 45,696 | | |
| | |
| |
| |
| |
| | |
| | |
| (a) | | Reflects oil and natural gas deliveries through March 31, 2006. |
|
| (b) | | Excludes taxes of $50.3 million recorded in 2006 due to the settlement of the SENIAT tax assessments. |
TABLE IV -— Quantities of Oil and Natural Gas Reserves Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. All Venezuelan reserves are attributable to
an operating service agreementthe OSA between
Benton-VincclerHarvest Vinccler and PDVSA, under which all mineral rights are owned by the government of Venezuela.
The Venezuelan
reserves include production projected throughgovernment unilaterally terminated the
end of the operating service agreementOSA in
July 2012. Benton-Vinccler has requested that the operating service agreement period be extended for the time sales were halted by the national civil work stoppage under the force majeure clause.April 2006.
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 economic changes.other relevant developments. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.
S-24
Proved
Developed Reservesdeveloped reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.
S-26
Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reservesproved 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 Reservesundeveloped reserves are
Proved Reservesproved 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 Reservesproved 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 Reservesproved reserves result from new information obtained from production history and changes in economic factors.
The evaluations of the oil and natural gas reserves as of December 31,
2003, 20022005 and
20012004 were prepared by Ryder Scott Company L.P., independent petroleum engineers.
The 2005 reserve information shown below has been reduced to exclude reserves formerly classified as proved undeveloped. Under SEC standards for the reporting of oil and natural gas reserves, proved reserves are estimated quantities of crude oil and natural gas “which geological data and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirsunder existing economic and operating conditions.” (Emphasis added). Our quantities of proved reserves were reduced to remove undeveloped reserves because the actions taken by the Venezuelan government beginning in 2005 under our OSA have created uncertainty as to whether those reserves will be recovered under the economic and operating conditions which currently exist in Venezuela. For ease of reference, the reclassified reserves are hereafter referred to as “Contractually Restricted Reserves”. In April 2006, the OSA was unilaterally terminated by the Venezuelan government and we are currently awaiting the conversion to Petrodelta. SeeNote 1 – Organization. Until we complete the conversion to Petrodelta, we will not have reserves to report under SEC guidelines and, accordingly, no reserves are reported as of December 31, 2006.
The tables shown below represent our interests in
the United Sates and Venezuela in each of the years.
| | | | | | | | | | | | | |
| | | | | | | Minority | | |
| | | | | | | Interest in | | |
| | | Venezuela
| | Venezuela
| | Net Total
|
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) | | | | | | | | | | | | |
Year ended December 31, 2003 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 95,168 | | | | (19,033 | ) | | | 76,135 | |
| Revisions of previous estimates | | | (521 | ) | | | 104 | | | | (417 | ) |
| Extensions, discoveries and improved recovery | | | 572 | | | | (114 | ) | | | 458 | |
| Production | | | (7,347 | ) | | | 1,469 | | | | (5,878 | ) |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Proved Reserves at end of the year | | | 87,872 | | | | (17,574 | ) | | | 70,298 | |
| | | |
| | | |
| | | |
| |
Year ended December 31, 2002 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 104,514 | | | | (20,903 | ) | | | 83,611 | |
| Revisions of previous estimates | | | 362 | | | | (72 | ) | | | 290 | |
| Extensions, discoveries and improved recovery | | | — | | | | — | | | | — | |
| Production | | | (9,708 | ) | | | 1,942 | | | | (7,766 | ) |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Proved Reserves at end of the year | | | 95,168 | | | | (19,033 | ) | | | 76,135 | |
| | | |
| | | |
| | | |
| |
| Russia – Geoilbent (34%) Proved Reserves at end of the year | | | | | | | | | | | 24,781 | |
| | | | | | | | | | | |
| |
Year ended December 31, 2001 | | | | | | | | | | | | |
| Proved Reserves at beginning of the year | | | 123,039 | | | | (24,608 | ) | | | 98,431 | |
| Revisions of previous estimates | | | (8,747 | ) | | | 1,749 | | | | (6,998 | ) |
| Purchases of reserves in place | | | — | | | | — | | | | — | |
| Extensions, discoveries and improved recovery | | | — | | | | — | | | | — | |
| Production | | | (9,778 | ) | | | 1,956 | | | | (7,822 | ) |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Proved Reserves at end of the year | | | 104,514 | | | | (20,903 | ) | | | 83,611 | |
| | | |
| | | |
| | | |
| |
| Russia – Arctic Gas (39%) Proved Reserves at end of the year | | | | | | | | | | | 20,964 | |
| | | | | | | | | | | |
| |
| Russia – Geoilbent (34%) Proved Reserves at end of the year | | | | | | | | | | | 29,668 | |
| | | | | | | | | | | |
| |
S-27S-25
| | | | | | | | | | | | | |
| | | | | | | Minority | | |
| | | | | | | Interest in | | |
| | | Venezuela
| | Venezuela
| | Net Total
|
Proved Developed Reserves at: | | | | | | | | | | | | |
| December 31, 2003 | | | 45,860 | | | | (9,172 | ) | | | 36,688 | |
| December 31, 2002 | | | 53,833 | | | | (10,767 | ) | | | 43,066 | |
| December 31, 2001 | | | 51,465 | | | | (10,293 | ) | | | 41,172 | |
| January 1, 2001 | | | 67,217 | | | | (13,443 | ) | | | 53,774 | |
| Russia – Arctic Gas Proved Reserves at end of the year | | | | | | | | | | | | |
| 2001 (39%) | | | | | | | | | | | 2,483 | |
| 2000 (29%) | | | | | | | | | | | 2,325 | |
| Russia – Geoilbent (34%) Proved Reserves at end of the year | | | | | | | | | | | | |
| 2002 | | | | | | | | | | | 11,840 | |
| 2001 | | | | | | | | | | | 15,658 | |
| 2000 | | | | | | | | | | | 14,913 | |
Proved Reserves-natural gas (MMcf) | | | | | | | | | | | | |
Year ended December 31, 2003 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 198,000 | | | | (39,600 | ) | | | 158,400 | |
| Revisions of previous estimates | | | 160 | | | | (32 | ) | | | 128 | |
| Extensions, discoveries and improved recovery | | | — | | | | — | | | | — | |
| Production | | | (2,660 | ) | | | 532 | | | | (2,128 | ) |
| | | |
| | | |
| | | |
| |
| Proved Reserves end of the year | | | 195,500 | | | | (39,100 | ) | | | 156,400 | |
| | | |
| | | |
| | | |
| |
Year ended December 31, 2002 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | — | | | | — | | | | — | |
| Revisions of previous estimates | | | — | | | | — | | | | — | |
| Extensions, discoveries and improved recovery | | | 198,000 | | | | (39,600 | ) | | | 158,400 | |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Proved Reserves end of the year | | | 198,000 | | | | (39,600 | ) | | | 158,400 | |
| | | |
| | | |
| | | |
| |
| Russia – Arctic Gas (39%) Proved Reserves – December 31, 2001 | | | | | | �� | | | | | 208,010 | |
| | | | | | | | | | | |
| |
| Russia – Arctic Gas (39%) Proved Reserves – December 31, 2000 | | | | | | | | | | | 152,496 | |
| | | | | | | | | | | |
| |
Proved Developed Reserves at: | | | | | | | | | | | | |
| December 31, 2003 | | | 106,147 | | | | (21,229 | ) | | | 84,918 | |
| December 31, 2002 | | | 105,000 | | | | (21,000 | ) | | | 84,000 | |
| Russia – Arctic Gas 2001 (39%) | | | | | | | | | | | 21,292 | |
| Russia – Arctic Gas 2000 (29%) | | | | | | | | | | | 17,801 | |
| | | | | | | | | | | | | |
| | | | | | | Minority | | |
| | | | | | | Interest in | | |
| | | Venezuela | | Venezuela | | Net Total |
| | | (in thousands) |
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Year ended December 31, 2006 | | | | | | | | | | | | |
| Proved Reserves at beginning of the year | | | 35,311 | | | | (7,062 | ) | | | 28,249 | |
Revisions of previous estimates(a) | | | (33,417 | ) | | | 6,683 | | | | (26,734 | ) |
| Production | | | (1,894 | ) | | | 379 | | | | (1,515 | ) |
| | | | | | | | | | | | | |
| Proved Reserves at end of the year | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| | |
TABLE V -(a) | Standardized Measure of Discounted Future Net Cash Flows Related | All reserves have been removed pending conversion to Proved Oil and Natural Gas Reserve QuantitiesPetrodelta. |
| | | | | | | | | | | | | |
Year ended December 31, 2005 | | | | | | | | | | | | |
| Proved Reserves at beginning of the year | | | 78,142 | | | | (15,628 | ) | | | 62,514 | |
Revisions of previous estimates(a) | | | (34,068 | ) | | | 6,813 | | | | (27,255 | ) |
| Production | | | (8,763 | ) | | | 1,753 | | | | (7,010 | ) |
| | | | | | | | | | | | | |
| Proved Developed Reserves at end of the year | | | 35,311 | | | | (7,062 | ) | | | 28,249 | |
| | | | | | | | | | | | | |
| | |
| (a) | | Includes primarily Contractually Restricted Reserves as well as other minor revisions. |
| | | | | | | | | | | | | |
Year ended December 31, 2004 | | | | | | | | | | | | |
| Proved Reserves at beginning of the year | | | 87,872 | | | | (17,574 | ) | | | 70,298 | |
| Revisions of previous estimates | | | (1,578 | ) | | | 316 | | | | (1,262 | ) |
| Production | | | (8,152 | ) | | | 1,630 | | | | (6,522 | ) |
| | | | | | | | | | | | | |
| Proved Reserves at end of the year | | | 78,142 | | | | (15,628 | ) | | | 62,514 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at: | | | | | | | | | | | | |
| December 31, 2005 | | | 35,311 | | | | (7,062 | ) | | | 28,249 | |
| December 31, 2004 | | | 45,488 | | | | (9,098 | ) | | | 36,390 | |
| January 1, 2004 | | | 45,860 | | | | (9,172 | ) | | | 36,688 | |
Proved Reserves-Natural gas (MMcf)
| | | | | | | | | | | | | |
Year ended December 31, 2006 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 58,918 | | | | (11,784 | ) | | | 47,134 | |
Revisions of previous estimates(a) | | | (54,412 | ) | | | 10,883 | | | | (43,529 | ) |
| Production | | | (4,506 | ) | | | 901 | | | | (3,605 | ) |
| | | | | | | | | | | | | |
| Proved Reserves end of the year | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| | |
| (a) | | All reserves have been removed pending conversion to Petrodelta. |
| | | | | | | | | | | | | |
Year ended December 31, 2005 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 164,282 | | | | (32,856 | ) | | | 131,426 | |
Revisions of previous estimates(a) | | | (79,687 | ) | | | 15,937 | | | | (63,750 | ) |
| Production | | | (25,677 | ) | | | 5,135 | | | | (20,542 | ) |
| | | | | | | | | | | | | |
| Proved Developed Reserves end of the year | | | 58,918 | | | | (11,784 | ) | | | 47,134 | |
| | | | | | | | | | | | | |
| | |
| (a) | | Includes primarily Contractually Restricted Reserves as well as other minor revisions. |
S-26
| | | | | | | | | | | | | |
Year ended December 31, 2004 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 195,500 | | | | (39,100 | ) | | | 156,400 | |
| Revisions of previous estimates | | | (159 | ) | | | 32 | | | | (127 | ) |
| Production | | | (31,059 | ) | | | 6,212 | | | | (24,847 | ) |
| | | | | | | | | | | | | |
| Proved Reserves end of the year | | | 164,282 | | | | (32,856 | ) | | | 131,426 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Proved Developed Reserves-Natural gas (MMcf) at: | | | | | | | | | | | | |
| December 31, 2006 | | | | | | | | | | | | |
| December 31, 2005 | | | 58,918 | | | | (11,784 | ) | | | 47,134 | |
| December 31, 2004 | | | 80,897 | | | | (16,179 | ) | | | 64,718 | |
| January 1, 2004 | | | 106,147 | | | | (21,229 | ) | | | 84,918 | |
TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
The tables shown below represent our interest in Venezuela in each of the years. In additionUntil we complete the conversion to thesePetrodelta, we will not have reserves is our 34 percent interest in Geoilbent at December 31, 2002to report under SEC guidelines and, our Arctic Gas interest of 39% at December 31, 2001. This combined with our Venezuela crude oil and natural gasaccordingly, no reserves represent our net interest in all reservesare reported as of December 31, 2003.2006. We report the results of Ryder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan reserves.
| | | | | | | | | | | | | |
| | | | | | | Minority | | | | |
| | | | | | | Interest in | | | | |
| | | Venezuela | | | Venezuela | | | Net Total | |
| | | | | | | (in thousands) | | | | | |
December 31, 2005(a) | | | | | | | | | | | | |
| Future cash inflows from sales of oil and gas | | $ | 1,029,630 | | | $ | (205,926 | ) | | $ | 823,704 | |
| Future production costs | | | (227,079 | ) | | | 45,416 | | | | (181,663 | ) |
| Future development costs | | | (27,917 | ) | | | 5,583 | | | | (22,334 | ) |
| Future income tax expenses | | | (239,386 | ) | | | 47,877 | | | | (191,509 | ) |
| | | | | | | | | | |
| Future net cash flows | | | 535,248 | | | | (107,050 | ) | | | 428,198 | |
| Effect of discounting net cash flows at 10% | | | (123,451 | ) | | | 24,691 | | | | (98,760 | ) |
| | | | | | | | | | |
| Standardized measure of discounted future net cash flows | | $ | 411,797 | | | $ | (82,359 | ) | | $ | 329,438 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
December 31, 2004 | | | | | | | | | | | | |
| Future cash inflows from sales of oil and gas | | $ | 1,852,045 | | | $ | (370,409 | ) | | $ | 1,481,636 | |
| Future production costs | | | (342,373 | ) | | | 68,475 | | | | (273,898 | ) |
| Future development costs | | | (141,565 | ) | | | 28,313 | | | | (113,252 | ) |
| Future income tax expenses | | | (428,833 | ) | | | 85,767 | | | | (343,066 | ) |
| | | | | | | | | | |
| Future net cash flows | | | 939,274 | | | | (187,854 | ) | | | 751,420 | |
| Effect of discounting net cash flows at 10% | | | (258,049 | ) | | | 51,609 | | | | (206,440 | ) |
| | | | | | | | | | |
| Standardized measure of discounted future net cash flows | | $ | 681,225 | | | $ | (136,245 | ) | | $ | 544,980 | |
| | | | | | | | | | |
| | |
| (a) | | Proved reserves do not include Contractually Restricted Reserves. |
S-28S-27
| | | | | | | | | | | | | |
| | | | | | | Minority | | |
| | | | | | | Interest in | | |
| | | Venezuela
| | Venezuela
| | Net Total
|
| | | (amounts in thousands) |
December 31, 2003 | | | | | | | | | | | | |
| Future cash inflow | | $ | 1,513,525 | | | $ | (302,705 | ) | | $ | 1,210,820 | |
| Future production costs | | | (382,577 | ) | | | 76,515 | | | | (306,062 | ) |
| Future development costs | | | (130,160 | ) | | | 26,032 | | | | (104,128 | ) |
| | | |
| | | |
| | | |
| |
| Future net revenue before income taxes | | | 1,000,788 | | | | (200,158 | ) | | | 800,630 | |
| 10% annual discount for estimated timing of cash flows | | | (319,152 | ) | | | 63,830 | | | | (255,322 | ) |
| | | |
| | | |
| | | |
| |
| Discounted future net cash flows before income taxes | | | 681,636 | | | | (136,328 | ) | | | 545,308 | |
| Future income taxes, discounted at 10% per annum | | | (223,172 | ) | | | 44,634 | | | | (178,538 | ) |
| | | |
| | | |
| | | |
| |
| Standardized measure of discounted future net cash flows | | $ | 458,464 | | | $ | (91,694 | ) | | $ | 366,770 | |
| | | |
| | | |
| | | |
| |
December 31, 2002 | | | | | | | | | | | | |
| Future cash flows | | $ | 1,510,346 | | | $ | (302,069 | ) | | $ | 1,208,277 | |
| Future production costs | | | (400,694 | ) | | | 80,139 | | | | (320,555 | ) |
| Future development costs | | | (192,671 | ) | | | 38,534 | | | | (154,137 | ) |
| | | |
| | | |
| | | |
| |
| Future net revenue before income taxes | | | 916,981 | | | | (183,396 | ) | | | 733,585 | |
| 10% annual discount for estimated timing of cash flows | | | (315,376 | ) | | | 63,075 | | | | (252,301 | ) |
| | | |
| | | |
| | | |
| |
| Discounted future net cash flows before income taxes | | | 601,605 | | | | (120,321 | ) | | | 481,284 | |
| Future income taxes, discounted at 10% per annum | | | (204,356 | ) | | | 40,871 | | | | (163,485 | ) |
| | | |
| | | |
| | | |
| |
| Standardized measure of discounted future net cash flows | | $ | 397,249 | | | $ | (79,450 | ) | | $ | 317,799 | |
| | | |
| | | |
| | | |
| |
| Russia – Geoilbent (34%) | | | | | | | | | | $ | 45,395 | |
| | | | | | | | | | | |
| |
December 31, 2001 | | | | | | | | | | | | |
| Future cash inflow | | $ | 1,030,404 | | | $ | (206,081 | ) | | $ | 824,323 | |
| Future production costs | | | (558,431 | ) | | | 111,686 | | | | (446,745 | ) |
| Future development costs | | | (142,006 | ) | | | 28,401 | | | | (113,605 | ) |
| | | |
| | | |
| | | |
| |
| Future net revenue before income taxes | | | 329,967 | | | | (65,994 | ) | | | 263,973 | |
| 10% annual discount for estimated timing of cash flows | | | (109,704 | ) | | | 21,941 | | | | (87,763 | ) |
| | | |
| | | |
| | | |
| |
| Discounted future net cash flows before income taxes | | | 220,263 | | | | (44,053 | ) | | | 176,210 | |
| Future income taxes, discounted at 10% per annum | | | (16,103 | ) | | | 3,221 | | | | (12,882 | ) |
| | | |
| | | |
| | | |
| |
| Standardized measure of discounted future net cash flows | | $ | 204,160 | | | $ | (40,832 | ) | | $ | 163,328 | |
| | | |
| | | |
| | | |
| |
| Russia – Arctic Gas (29%) | | | | | | | | | | $ | 82,205 | |
| | | | | | | | | | | |
| |
| Russia – Geoilbent (34%) | | | | | | | | | | $ | 70,648 | |
| | | | | | | | | | | |
| |
| | | | | | | | | | | | | |
| | | Net Venezuela | |
| | | 2006(a) | | | 2005 | | | 2004 | |
| | | (in thousands) | |
| Standardized Measure at January 1 | | $ | 329,438 | | | $ | 544,980 | | | $ | 366,770 | |
| Sales of oil and natural gas, net of related costs | | | (40,361 | ) | | | (124,638 | ) | | | (122,215 | ) |
| Revisions to estimates of proved reserves | | | | | | | | | | | | |
| Net changes in prices, development and production costs | | | — | | | | 262,852 | | | | 333,237 | |
| Quantities | | | — | | | | (365,565 | ) | | | (7,597 | ) |
| Extensions, discoveries and improved recovery, net of future costs | | | — | | | | — | | | | — | |
| Accretion of discount | | | — | | | | 80,202 | | | | 54,531 | |
| Net change in income taxes | | | — | | | | 109,030 | | | | (78,504 | ) |
| Development costs incurred | | | 501 | | | | 7,130 | | | | 31,329 | |
| Changes in timing and other | | | (289,578 | ) | | | (184,553 | ) | | | (32,571 | ) |
| | | | | | | | | | |
| Standardized Measure at December 31 | | $ | — | | | $ | 329,438 | | | $ | 544,980 | |
| | | | | | | | | | |
| | |
TABLE VI — | Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves |
| | | | | | | | | | | | | |
| | | | | | | Net Venezuela
| | |
| | | 2003
| | 2002
| | 2001
|
| | | (amounts in thousands) |
| Present Value at January 1 | | $ | 317,799 | | | $ | 163,328 | | | $ | 284,549 | |
| Sales of oil and natural gas, net of related costs | | | (59,720 | ) | | | (76,098 | ) | | | (64,139 | ) |
| Revisions to estimates of Proved Reserves | | | | | | | | | | | | |
| Net changes in prices, development and production costs | | | 76,037 | | | | 310,043 | | | | (141,429 | ) |
| Quantities | | | (1,584 | ) | | | 611 | | | | (26,198 | ) |
| Extensions, discoveries and improved recovery, net of future costs | | | 4,971 | | | | 89,670 | | | | — | |
| Accretion of discount | | | 48,128 | | | | 17,621 | | | | 36,846 | |
| Net change in income taxes | | | (15,053 | ) | | | (150,603 | ) | | | 71,033 | |
| Development costs incurred | | | 46,463 | | | | 40,532 | | | | 23,768 | |
| Changes in timing and other | | | (50,271 | ) | | | (77,305 | ) | | | (21,102 | ) |
| | | |
| | | |
| | | |
| |
| Present Value at December 31 | | $ | 366,770 | | | $ | 317,799 | | | $ | 163,328 | |
| | | |
| | | |
| | | |
| |
S-29
Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Russia Equity Affiliates as of September 30, their fiscal year end.
In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
Geoilbent (34 percent ownership until sold September 25, 2003) and Arctic Gas (39 percent ownership not subject to certain sale and transfer restrictions at December 31, 2001, until Arctic Gas was sold on April 12, 2002, respectively), which are accounted for under the equity method, have been included at their respective ownership interests in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, results of operations for oil and natural gas producing activities in Russia reflect the years ended September 30, 2002 and 2001.
TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
| | | | | | | | | | | | | |
| | | | | | | | | | | Total Equity |
| | | Arctic Gas
| | Geoilbent
| | Affiliates
|
Year Ended September 25, 2003 | | | | | | | | | | | | |
| Development costs | | $ | — | | | $ | 3,474 | | | $ | 3,474 | |
| Exploration costs | | | — | | | | 1,034 | | | | 1,034 | |
| | | |
| | | |
| | | |
| |
| | | $ | — | | | $ | 4,508 | | | $ | 4,508 | |
| | | |
| | | |
| | | |
| |
Year Ended September 30, 2002 | | | | | | | | | | | | |
| Development costs | | $ | — | | | $ | 8,599 | | | $ | 8,599 | |
| Exploration costs | | | 16,156 | | | | 498 | | | | 16,654 | |
| | | |
| | | |
| | | |
| |
| | | $ | 16,156 | | | $ | 9,097 | | | $ | 25,253 | |
| | | |
| | | |
| | | |
| |
Year Ended September 30, 2001 | | | | | | | | | | | | |
| Development costs | | $ | — | | | $ | 11,483 | | | $ | 11,483 | |
| Exploration costs | | | 8,136 | | | | 2,074 | | | | 10,210 | |
| | | |
| | | |
| | | |
| |
| | | $ | 8,136 | | | $ | 13,557 | | | $ | 21,693 | |
| | | |
| | | |
| | | |
| |
TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):
| | | | | | | | | | | | | |
| | | | | | | | | | | Total Equity |
| | | Arctic Gas
| | Geoilbent
| | Affiliates
|
September 25, 2003 | | | | | | | | | | | | |
| Proved property costs | | $ | — | | | $ | 102,753 | | | $ | 102,753 | |
| Oilfield inventories | | | — | | | | 2,530 | | | | 2,530 | |
| Less accumulated depletion and impairment | | | — | | | | (72,333 | ) | | | (72,333 | ) |
| | | |
| | | |
| | | |
| |
| | | $ | — | | | $ | 32,950 | | | $ | 32,950 | |
| | | |
| | | |
| | | |
| |
September 30, 2002 | | | | | | | | | | | | |
| Proved property costs | | $ | — | | | $ | 94,404 | | | $ | 94,404 | |
| Costs excluded from amortization | | | — | | | | 272 | | | | 272 | |
| Oilfield inventories | | | — | | | | 2,348 | | | | 2,348 | |
| Less accumulated depletion and impairment | | | — | | | | (31,440 | ) | | | (31,440 | ) |
| | | |
| | | |
| | | |
| |
| | | $ | — | | | $ | 65,584 | | | $ | 65,584 | |
| | | |
| | | |
| | | |
| |
September 30, 2001 | | | | | | | | | | | | |
| Proved property costs | | $ | 5,786 | | | $ | 85,677 | | | $ | 91,463 | |
| Costs excluded from amortization | | | 11,549 | | | | — | | | | 11,549 | |
| Oilfield inventories | | | 175 | | | | 4,357 | | | | 4,532 | |
| Less accumulated depletion and impairment | | | (389 | ) | | | (22,203 | ) | | | (22,592 | ) |
| | | |
| | | |
| | | |
| |
| | | $ | 17,121 | | | $ | 67,831 | | | $ | 84,952 | |
| | | |
| | | |
| | | |
| |
S-30
TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
| | | | | | | | | | | | | |
| | | | | | | | | | | Total Equity |
| | | Arctic Gas
| | Geoilbent
| | Affiliates
|
Year ended September 25, 2003 | | | | | | | | | | | | |
| Oil sales | | $ | — | | | $ | 27,876 | | | $ | 27,876 | |
| Expenses: | | | | | | | | | | | | |
| Operating, selling and distribution expenses and taxes other than on income | | | — | | | | 16,088 | | | | 16,088 | |
| Depletion | | | — | | | | 6,215 | | | | 6,215 | |
| Write-down of oil and gas properties | | | — | | | | 32,300 | | | | 32,300 | |
| Income tax expense | | | — | | | | 2,073 | | | | 2,073 | |
| | | |
| | | |
| | | |
| |
| Total expenses | | | — | | | | 56,676 | | | | 56,676 | |
| | | |
| | | |
| | | |
| |
| Results of operations from oil and natural gas producing activities | | $ | — | | | $ | (28,800 | ) | | $ | (28,800 | ) |
| | | |
| | | |
| | | |
| |
Year ended September 30, 2002 | | | | | | | | | | | | |
| Oil sales | | $ | 3,554 | | | $ | 31,039 | | | $ | 34,593 | |
| Expenses: | | | | | | | | | | | | |
| Operating, selling and distribution expenses and taxes other than on income | | | 3,102 | | | | 16,902 | | | | 20,004 | |
| Depletion | | | 139 | | | | 9,237 | | | | 9,376 | |
| Income tax expense | | | 19 | | | | 1,955 | | | | 1,974 | |
| | | |
| | | |
| | | |
| |
| Total expenses | | | 3,260 | | | | 28,094 | | | | 31,354 | |
| | | |
| | | |
| | | |
| |
| Results of operations from oil and natural gas producing activities | | $ | 294 | | | $ | 2,945 | | | $ | 3,239 | |
| | | |
| | | |
| | | |
| |
Year ended September 30, 2001 | | | | | | | | | | | | |
| Oil sales | | $ | 4,016 | | | $ | 34,261 | | | $ | 38,277 | |
| Expenses: | | | | | | | | | | | | |
| Operating, selling and distribution expenses and taxes other than on income | | | 3,381 | | | | 16,083 | | | | 19,464 | |
| Depletion | | | 311 | | | | 5,072 | | | | 5,383 | |
| Income tax expense | | | 80 | | | | 3,742 | | | | 3,822 | |
| | | |
| | | |
| | | |
| |
| Total expenses | | | 3,772 | | | | 24,897 | | | | 28,669 | |
| | | |
| | | |
| | | |
| |
| Results of operations from oil and natural gas producing activities | | $ | 244 | | | $ | 9,364 | | | $ | 9,608 | |
| | | |
| | | |
| | | |
| |
TABLE IV — Quantities of Oil and Natural Gas Reserves
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Geoilbent and Arctic Gas oil and gas fields are situated on land belonging to the Government of the Russian Federation. Each obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Geoilbent had licenses to develop the North Gubkinskoye and South Tarasovskoye fields in western Siberia. Our 34 percent equity investment in Geoilbent was sold September 25, 2003. Arctic Gas had licenses to develop the Samburg and Yevo-Yakhinskiy fields in western Siberia. Arctic Gas was sold on April 12, 2002.
The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.
Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.
S-31
Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.
Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.
Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.
| | | | | | | | | | | | | |
| | | | | | | | | | | Total Equity |
| | | Arctic Gas
| | Geoilbent
| | Affiliates
|
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) | | | | | | | | | | | | |
Year ended September 30, 2003 | | | | | | | | | | | | |
| Proved reserves beginning of the year | | | — | | | | 25,356 | | | | 25,356 | |
| Revisions of previous estimates | | | — | | | | 537 | | | | 537 | |
| Extensions, discoveries and improved recovery | | | — | | | | 962 | | | | 962 | |
| Production | | | — | | | | (1,942 | ) | | | (1,942 | ) |
| Sales of reserves in place | | | — | | | | (24,913 | ) | | | (24,913 | ) |
| | | |
| | | |
| | | |
| |
| Proved reserves at end of the year | | | — | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
Year ended September 30, 2002 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 20,965 | | | | 29,668 | | | | 50,633 | |
| Revisions of previous estimates | | | — | | | | (3,455 | ) | | | (3,455 | ) |
| Extensions, discoveries and improved recovery | | | — | | | | 1,493 | | | | 1,493 | |
| Production | | | (89 | ) | | | (2,350 | ) | | | (2,439 | ) |
| Sales of reserves in place | | | (20,876 | ) | | | — | | | | (20,876 | ) |
| | | |
| | | |
| | | |
| |
| Proved Reserves at end of the year | | | — | | | | 25,356 | | | | 25,356 | |
| | | |
| | | |
| | | |
| |
Year ended September 30, 2001 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 15,821 | | | | 32,614 | | | | 48,435 | |
| Revisions of previous estimates | | | 5,327 | | | | (5,594 | ) | | | (267 | ) |
| Extensions, discoveries and improved recovery | | | — | | | | 4,411 | | | | 4,411 | |
| Production | | | (183 | ) | | | (1,763 | ) | | | (1,946 | ) |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Proved Reserves at end of the year | | | 20,965 | | | | 29,668 | | | | 50,633 | |
| | | |
| | | |
| | | |
| |
Proved Developed Reserves at: | | | | | | | | | | | | |
| September 30, 2003 | | | — | | | | — | | | | — | |
| September 30, 2002 | | | — | | | | 13,200 | | | | 13,200 | |
| September 30, 2001 | | | 2,483 | | | | 15,658 | | | | 18,141 | |
| October 1, 2000 | | | 2,325 | | | | 14,913 | | | | 17,238 | |
Proved Reserves-natural gas (MMcf) | | | | | | | | | | | | |
Year ended September 30, 2002 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 208,010 | | | | — | | | | 208,010 | |
| Revisions of previous estimates | | | — | | | | — | | | | — | |
| Extensions, discoveries and improved recovery | | | — | | | | — | | | | — | |
| Production | | | — | | | | — | | | | — | |
| Sales of reserves in place | | | (208,010 | ) | | | — | | | | (208,010 | ) |
| | | |
| | | |
| | | |
| |
| Proved Reserves end of the year | | | — | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
S-32
| | | | | | | | | | | | | |
| | | | | | | | | | | Total Equity |
| | | Arctic Gas
| | Geoilbent
| | Affiliates
|
Year ended September 30, 2001 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 152,496 | | | | — | | | | 152,496 | |
| Revisions of previous estimates | | | 55,514 | | | | — | | | | 55,514 | |
| Extensions, discoveries and improved recovery | | | — | | | | — | | | | — | |
| Production | | | — | | | | — | | | | — | |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Proved Reserves end of the year | | | 208,010 | | | | — | | | | 208,010 | |
| | | |
| | | |
| | | |
| |
Proved Developed Reserves at: | | | | | | | | | | | | |
| September 30, 2002 | | | — | | | | — | | | | — | |
| September 30, 2001 | | | 21,292 | | | | — | | | | 21,292 | |
| October 1, 2000 | | | 17,801 | | | | — | | | | 17,801 | |
| (a) | | |
TABLE V -
| | Standardized Measure of Discounted Future Net Cash Flows RelatedAll reserves have been removed pending conversion to Proved Oil and Natural Gas Reserve QuantitiesPetrodelta. |
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
| | | | | | | | | | | | | |
| | | | | | | | | | | Total Equity |
| | | Arctic Gas
| | Geoilbent
| | Affiliates
|
| | | | | | | (amounts in thousands) | | | | |
September 30, 2003 | | | | | | | | | | | | |
| Future cash inflow | | $ | — | | | $ | 481,557 | | | $ | 481,557 | |
| Future production costs | | | — | | | | (229,982 | ) | | | (229,982 | ) |
| Future development costs | | | — | | | | (36,666 | ) | | | (36,666 | ) |
| | | |
| | | |
| | | |
| |
| Future net revenue before income taxes | | | — | | | | 214,909 | | | | 214,909 | |
| 10% annual discount for estimated timing of cash flows | | | — | | | | (99,948 | ) | | | (99,948 | ) |
| | | |
| | | |
| | | |
| |
| Discounted future net cash flows before income taxes | | | — | | | | 114,961 | | | | 114,961 | |
| Future income taxes, discounted at 10% per annum | | | — | | | | (23,163 | ) | | | (23,163 | ) |
| | | |
| | | |
| | | |
| |
| Standardized measure of discounted future net cash flows | | $ | — | | | $ | 91,798 | | | $ | 91,798 | |
| | | |
| | | |
| | | |
| |
September 30, 2002 | | | | | | | | | | | | |
| Future cash inflow | | $ | — | | | $ | 469,837 | | | $ | 469,837 | |
| Future production costs | | | — | | | | (203,754 | ) | | | (203,754 | ) |
| Future development costs | | | — | | | | (40,707 | ) | | | (40,707 | ) |
| | | |
| | | |
| | | |
| |
| Future net revenue before income taxes | | | — | | | | 225,376 | | | | 225,376 | |
| 10% annual discount for estimated timing of cash flows | | | — | | | | (108,147 | ) | | | (108,147 | ) |
| | | |
| | | |
| | | |
| |
| Discounted future net cash flows before income taxes | | | — | | | | 117,229 | | | | 117,229 | |
| Future income taxes, discounted at 10% per annum | | | — | | | | (24,290 | ) | | | (24,290 | ) |
| | | |
| | | |
| | | |
| |
| Standardized measure of discounted future net cash flows | | $ | — | | | $ | 92,939 | | | $ | 92,939 | |
| | | |
| | | |
| | | |
| |
September 30, 2001 | | | | | | | | | | | | |
| Future cash inflow | | $ | 630,340 | | | $ | 434,348 | | | $ | 1,064,688 | |
| Future production costs | | | (373,458 | ) | | | (251,335 | ) | | | (624,793 | ) |
| Future development costs | | | (49,139 | ) | | | (37,020 | ) | | | (86,159 | ) |
| | | |
| | | |
| | | |
| |
| Future net revenue before income taxes | | | 207,743 | | | | 145,993 | | | | 353,736 | |
| 10% annual discount for estimated timing of cash flows | | | (99,343 | ) | | | (64,868 | ) | | | (164,211 | ) |
| | | |
| | | |
| | | |
| |
| Discounted future net cash flows before income taxes | | | 108,400 | | | | 81,125 | | | | 189,525 | |
| Future income taxes, discounted at 10% per annum | | | (26,195 | ) | | | (10,477 | ) | | | (36,672 | ) |
| | | |
| | | |
| | | |
| |
| Standardized measure of discounted future net cash flows | | $ | 82,205 | | | $ | 70,648 | | | $ | 152,853 | |
| | | |
| | | |
| | | |
| |
S-33
| | |
TABLE VI - Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
|
| | | | | | | | | | | | | |
| | | | | | | Equity Affiliates | | |
| | |
|
| | | 2003
| | 2002
| | 2001
|
| | | (amounts in thousands) |
| Present Value at October 1 | | $ | 92,939 | | | $ | 152,853 | | | $ | 171,605 | |
| Sales of oil and natural gas, net of related costs | | | (20,410 | ) | | | (23,644 | ) | | | (19,001 | ) |
| Revisions to estimates of Proved Reserves | | | | | | | | | | | | |
| Net changes in prices, development and production costs | | | (5,522 | ) | | | 76,545 | | | | (39,880 | ) |
| Quantities | | | 3,178 | | | | (10,007 | ) | | | 8,881 | |
| Sales of reserves in place | | | (91,797 | ) | | | (82,205 | ) | | | — | |
| Extensions, discoveries and improved recovery, net of future costs | | | 1,245 | | | | 2,031 | | | | 18,767 | |
| Accretion of discount | | | 11,723 | | | | 7,065 | | | | 21,468 | |
| Net change in income taxes | | | 1,127 | | | | 1,145 | | | | 6,400 | |
| Development costs incurred | | | 4,507 | | | | 8,999 | | | | 17,110 | |
| Changes in timing and other | | | 3,010 | | | | (39,843 | ) | | | (32,497 | ) |
| | | |
| | | |
| | | |
| |
| Present Value at September 30 | | $ | — | | | $ | 92,939 | | | $ | 152,853 | |
| | | |
| | | |
| | | |
| |
S-34S-28
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | |
| | | | HARVEST NATURAL RESOURCES, INC. |
| | | |
(Registrant) |
| | |
| |
Date: March 9, 2004 | 13, 2007 | By: | | /s/ Peter J. HillJames A. Edmiston | |
| | | |
|
| James A. Edmiston | | | | Peter J. Hill |
| | | | Chief Executive Officer | |
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed by the following persons on the 9th13th day of March, 2004,2007, on behalf of the registrant and in the capacities indicated:
| | | | | |
Signature
| | | | Title
|
| | | | |
/s/Peter J. Hill James A. Edmiston | | | | Director, President and Chief Executive Officer |
| | Officer | | |
Peter J. HillJames A. Edmiston | | | | |
| | | | | |
/s/ Steven W. Tholen Steven W. Tholen | | | | Senior Vice President — Finance, Chief Financial |
| | Officer and Treasurer |
Steven W. Tholen
(Principal Financial Officer) | | | | |
| | | | |
| /s/ Kurt A. Nelson | | | | Vice President-Controller, Chief Accounting Officer |
| | | | |
| Kurt A. Nelson | | | | |
| (Principal Accounting Officer) | | |
| | |
/s/ Stephen D. Chesebro’ | | Chairman of the Board and Director |
| | |
Stephen D. Chesebro’ | | |
| | |
/s/ John U. Clarke | | Director |
| | |
John U. Clarke | | |
| | |
/s/ Byron A. Dunn | | Director |
| | |
Byron A. Dunn | | |
| | |
/s/ H. H. Hardee | | Director |
| | |
H.H. Hardee | | |
| | |
/s/ Patrick M. Murray | | Director |
| | |
Patrick M. Murray | | |
S-35
SCHEDULE II
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(in thousands)
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Additions
| | | | |
| | | Balance at | | | | | | Charged to | | Deductions | | Balance at |
| | | Beginning | | Charged to | | Other | | From | | End of |
| | | of Year
| | Income
| | Accounts
| | Reserves
| | Year
|
At December 31, 2003 | | | | | | | | | | | | | | | | | | | | |
| Amounts deducted from applicable assets |
| Accounts receivable | | $ | 3,525 | | | $ | 205 | | | $ | — | | | $ | 375 | | | $ | 3,355 | |
| Deferred tax valuation allowance | | | 39,146 | | | | 9,219 | | | | — | | | | — | | | | 48,365 | |
| Investment at cost | | | 1,350 | | | | — | | | | — | | | | — | | | | 1,350 | |
At December 31, 2002 | | | | | | | | | | | | | | | | | | | | |
| Amounts deducted from applicable assets |
| Accounts receivable | | $ | 6,512 | | | $ | 289 | | | $ | — | | | $ | 3,276 | | | $ | 3,525 | |
| Deferred tax valuation allowance | | | 19,700 | | | | 20,577 | | | | — | | | | 1,131 | | | | 39,146 | |
| Investment at cost | | | 1,350 | | | | — | | | | — | | | | — | | | | 1,350 | |
At December 31, 2001 | | | | | | | | | | | | | | | | | | | | |
| Amounts deducted from applicable assets |
| Accounts receivable | | $ | 6,518 | | | $ | 330 | | | $ | — | | | $ | 336 | | | $ | 6,512 | |
| Deferred tax valuation allowance | | | 54,207 | | | | 14,352 | | | | (11,008 | ) | | | 37,851 | | | | 19,700 | |
| Investment at cost | | | 1,350 | | | | — | | | | — | | | | — | | | | 1,350 | |
S-36
SCHEDULE III
Financial Statements and Notes
for LLC Geoilbent
LLC Geoilbent
Financial Statements
30 September 2003
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and
Owners of Limited Liability Company Geoilbent
In our opinion, the accompanying balance sheets and the related statements of income, cash flows and changes in stockholders’ equity, present fairly, in all material respects, the financial position of LLC Geoilbent (the “Company”) at 30 September 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended 30 September 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Notes 4 and 10 to the financial statements, the Company has a long-term debt facility for which it is in violation of certain loan covenants and therefore the lender may declare the loan to be in default and can accelerate the maturity. Accordingly, this long-term debt has been classified in the accompanying financial statements as a current liability resulting in a working capital deficit of approximately US$35,772,000 as at 30 September 2003 which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to this matter are also described in Note 4. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
ZAO PricewaterhouseCoopers Audit
Moscow, Russian Federation
2 March 2003
LLC GEOILBENT
BALANCE SHEETS
(expressed in thousand of US Dollars)
| | | | | | | | | | | | | |
| | | | | | | As at | | As at |
| | | Notes
| | 30 September 2003
| | 30 September 2002
|
Assets | | | | | | | | | | | | |
| Cash and cash equivalents | | | | | | | 680 | | | | 2,001 | |
| Restricted cash | | | 10 | | | | 1,217 | | | | 1,469 | |
| Accounts receivable and advances to suppliers | | | 7 | | | | 7,161 | | | | 6,308 | |
| Inventories | | | 8 | | | | 8,018 | | | | 7,201 | |
| Deferred income tax, current | | | 14 | | | | 966 | | | | 1,806 | |
| | | |
| | | |
| | | |
| |
Total current assets | | | | | | | 18,042 | | | | 18,785 | |
| Oil and gas producing properties, full cost method | | | 9 | | | | 89,469 | | | | 185,989 | |
| Deferred income tax, non-current | | | 14 | | | | — | | | | 696 | |
| Other long term assets | | | | | | | — | | | | 130 | |
| | | |
| | | |
| | | |
| |
Total assets | | | | | | | 107,511 | | | | 205,600 | |
| | | |
| | | |
| | | |
| |
Liabilities and Stockholders’ Equity | | | | | | | | | | | | |
| Current portion of long-term debt | | | 10 | | | | 37,500 | | | | 22,550 | |
| Accounts payable | | | | | | | 6,559 | | | | 15,244 | |
| Trade advances | | | | | | | 993 | | | | 3,000 | |
| Taxes payable | | | 11 | | | | 7,858 | | | | 12,354 | |
| Other payables and accrued liabilities | | | | | | | 904 | | | | 903 | |
| | | |
| | | |
| | | |
| |
Total current liabilities | | | | | | | 53,814 | | | | 54,051 | |
| | | |
| | | |
| | | |
| |
| Long-term debt | | | 10 | | | | — | | | | 7,500 | |
| Asset retirement obligation | | | 3 | | | | 734 | | | | — | |
| | | |
| | | |
| | | |
| |
Total liabilities | | | | | | | 54,548 | | | | 61,551 | |
| | | |
| | | |
| | | |
| |
Commitments and contingent liabilities | | | 16 | | | | — | | | | — | |
| Contributed capital | | | 12 | | | | 82,518 | | | | 82,518 | |
| Retained earnings (accumulated deficit) | | | | | | | (23,353 | ) | | | 61,531 | |
| Accumulated other comprehensive loss | | | | | | | (6,202 | ) | | | — | |
| | | |
| | | |
| | | |
| |
Total stockholders’ equity | | | | | | | 52,963 | | | | 144,049 | |
| | | |
| | | |
| | | |
| |
Total liabilities and stockholders’ equity | | | | | | | 107,511 | | | | 205,600 | |
| | | |
| | | |
| | | |
| |
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
STATEMENTS OF INCOME
(expressed in thousand of US Dollars)
| | | | | | | | | | | | | | | | | |
| | | | | | | Year ended | | Year ended | | Year ended |
| | | Notes
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
Total sales and other operating revenues | | | 13 | | | | 82,307 | | | | 91,598 | | | | 101,159 | |
| | | |
| | | |
| | | |
| | | |
| |
Costs and other deductions | | | | | | | | | | | | | | | | |
| Operating expenses | | | | | | | 15,801 | | | | 15,360 | | | | 11,415 | |
| Selling and distribution expenses | | | | | | | 5,893 | | | | 6,696 | | | | 9,876 | |
| General and administrative expenses | | | | | | | 9,456 | | | | 8,335 | | | | 5,650 | |
| Depletion and amortization expense | | | | | | | 18,278 | | | | 27,168 | | | | 14,918 | |
| Impairment of property, plant and equipment | | | 9 | | | | 95,000 | | | | — | | | | — | |
| Taxes other than income tax | | | 14 | | | | 25,625 | | | | 27,657 | | | | 26,011 | |
| | | |
| | | |
| | | |
| | | |
| |
Total costs and other deductions | | | | | | | 170,053 | | | | 85,216 | | | | 67,870 | |
| | | |
| | | |
| | | |
| | | |
| |
Other income and expense | | | | | | | | | | | | | | | | |
| Exchange gain, net | | | | | | | (1,566 | ) | | | (2,053 | ) | | | (781 | ) |
| Interest expense, net | | | | | | | 1,992 | | | | 4,629 | | | | 7,547 | |
| Other non-operating income, net | | | | | | | (481 | ) | | | (381 | ) | | | (648 | ) |
| | | |
| | | |
| | | |
| | | |
| |
Total other expense (income) | | | | | | | (55 | ) | | | 2,195 | | | | 6,118 | |
| | | |
| | | |
| | | |
| | | |
| |
Income (loss) before income tax | | | | | | | (87,691 | ) | | | 4,187 | | | | 27,171 | |
| | | |
| | | |
| | | |
| | | |
| |
Income tax expense | | | 14 | | | | | | | | | | | | | |
| Current income tax expense | | | | | | | 3,542 | | | | 2,804 | | | | 6,751 | |
| Deferred income tax benefit | | | | | | | (6,659 | ) | | | (2,502 | ) | | | — | |
| | | |
| | | |
| | | |
| | | |
| |
Total income tax expense (benefit) | | | | | | | (3,117 | ) | | | 302 | | | | 6,751 | |
| | | |
| | | |
| | | |
| | | |
| |
Income (loss) before cumulative effect of change in accounting principle, net of tax | | | | | | | (84,574 | ) | | | 3,885 | | | | 20,420 | |
| Cumulative effect of change in accounting principle, net of tax | | | 3 | | | | (310 | ) | | | — | | | | — | |
| | | |
| | | |
| | | |
| | | |
| |
Net income (loss) | | | | | | | (84,884 | ) | | | 3,885 | | | | 20,420 | |
| | | |
| | | |
| | | |
| | | |
| |
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
STATEMENTS OF CASHFLOWS
(expressed in thousand of US Dollars)
| | | | | | | | | | | | | |
| | | Year ended | | Year ended | | Year ended |
| | | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
Cash flows from operating activities | | | | | | | | | | | | |
| Net income (loss) | | | (84,884 | ) | | | 3,885 | | | | 20,420 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
| Depletion and amortization expense | | | 18,278 | | | | 27,168 | | | | 14,918 | |
| Impairment of oil and gas properties | | | 95,000 | | | | — | | | | — | |
| Amortization of financing costs | | | 130 | | | | 520 | | | | 520 | |
| Exchange gain | | | (1,566 | ) | | | (2,053 | ) | | | (781 | ) |
| Deferred tax benefit | | | (6,659 | ) | | | (2,502 | ) | | | — | |
| Decrease/(increase) in accounts receivable and advances to suppliers | | | (631 | ) | | | 403 | | | | 85 | |
| Decrease/(increase) in inventories | | | (544 | ) | | | 6,362 | | | | (4,700 | ) |
| Increase/(decrease) in accounts payable | | | (9,030 | ) | | | (3,407 | ) | | | 11,902 | |
| Increase/(decrease) in trade advances | | | (2,070 | ) | | | (5,747 | ) | | | 3,785 | |
| Increase/(decrease) in taxes payable | | | (4,822 | ) | | | 5,436 | | | | 4,780 | |
| Decrease in other payables and accrued liabilities | | | (28 | ) | | | (1,378 | ) | | | (2,386 | ) |
| | | |
| | | |
| | | |
| |
Cash provided by operating activities | | | 3,174 | | | | 28,687 | | | | 48,543 | |
| | | |
| | | |
| | | |
| |
Cash flow from investing activities | | | | | | | | | | | | |
| Capital expenditures | | | (13,257 | ) | | | (26,755 | ) | | | (39,874 | ) |
| Proceeds on disposal of oil and gas producing properties | | | 1,023 | | | | 286 | | | | 191 | |
| Disposal/(purchase) of investments | | | — | | | | 367 | | | | (129 | ) |
| | | |
| | | |
| | | |
| |
Net cash used in investing activities | | | (12,234 | ) | | | (26,102 | ) | | | (39,812 | ) |
| | | |
| | | |
| | | |
| |
Cash flows from financing activities | | | | | | | | | | | | |
| Payment of short-term borrowings from founders | | | — | | | | — | | | | (717 | ) |
| Payment of short-terms borrowings | | | — | | | | (3,000 | ) | | | (3,845 | ) |
| Proceeds from short-term borrowings | | | — | | | | — | | | | 6,446 | |
| Proceeds from long-term borrowings from founders | | | — | | | | 7,500 | | | | — | |
| Payments of long-term borrowings | | | (550 | ) | | | (18,200 | ) | | | (10,455 | ) |
| Proceeds from long-term borrowings | | | 8,000 | | | | — | | | | — | |
| Decrease in restricted cash | | | 252 | | | | 8,738 | | | | 2,153 | |
| | | |
| | | |
| | | |
| |
Net cash provided by (used in) financing activities | | | 7,702 | | | | (4,962 | ) | | | (6,418 | ) |
| | | |
| | | |
| | | |
| |
| Effect of foreign exchange on cash balances | | | 37 | | | | (31 | ) | | | (37 | ) |
| | | |
| | | |
| | | |
| |
Net decrease in cash and cash equivalents | | | (1,321 | ) | | | (2,408 | ) | | | 2,276 | |
| Cash and cash equivalents, beginning of year | | | 2,001 | | | | 4,409 | | | | 2,133 | |
| | | |
| | | |
| | | |
| |
| Cash and cash equivalents, end of year | | | 680 | | | | 2,001 | | | | 4,409 | |
| | | |
| | | |
| | | |
| |
Supplemental cash flow information | | | | | | | | | | | | |
| Interest paid | | | 1,977 | | | | 4,862 | | | | 7,609 | |
| Income taxes paid | | | 2,388 | | | | 2,747 | | | | 6,906 | |
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(expressed in thousands of US Dollars except as indicated)
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Total |
| | | Contributed | | Retained earnings | | Accumulated other | | stockholders' |
| | | Capital
| | (accumulated deficit)
| | comprehensive loss
| | equity
|
Balance at 30 September 2000 | | | 82,518 | | | | 37,226 | | | | — | | | | 119,744 | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income and total comprehensive income | | | — | | | | 20,420 | | | | — | | | | 20,420 | |
| | | |
| | | |
| | | |
| | | |
| |
Balance at 30 September 2001 | | | 82,518 | | | | 57,646 | | | | — | | | | 140,164 | |
| | | |
| | | |
| | | |
| | | |
| |
| Net income and total comprehensive income | | | — | | | | 3,885 | | | | — | | | | 3,885 | |
| | | |
| | | |
| | | |
| | | |
| |
Balance at 30 September 2002 | | | 82,518 | | | | 61,531 | | | | — | | | | 144,049 | |
| | | |
| | | |
| | | |
| | | |
| |
| Net loss | | | — | | | | (84,884 | ) | | | — | | | | (84,884 | ) |
| Cumulative translation adjustment | | | — | | | | — | | | | (6,202 | ) | | | (6,202 | ) |
| | | | | | | | | | | | | | | |
| |
| Total comprehensive loss | | | | | | | | | | | | | | | (91,086 | ) |
| | | |
| | | |
| | | |
| | | |
| |
Balance at 30 September 2003 | | | 82,518 | | | | (23,353 | ) | | | (6,202 | ) | | | 52,963 | |
| | | |
| | | |
| | | |
| | | |
| |
The accompanying notes are an integral part of these financial statements.
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 1: Organization
LLC Geoilbent (the “Company”) is engaged in the development and production of oil and gas in the North Gubkinskoye and South Tarasovskoye fields. These fields are located in the West Siberian region of the Russian Federation, approximately 2,000 miles northeast of Moscow. The Company was established in December 1991 by two Russian oil companies, OAO Purneftegas (“PNG”) and OAO Purneftegasgeologia (“PNGG”), and by Harvest Natural Resources, Inc. (“Harvest”, formerly, Benton Oil and Gas Company) of the United States, which contributed 33%, 33% and 34%, respectively, of the Company’s charter capital, in accordance with the Company’s Foundation Document. In January 2002, PNG and PNGG transferred their stakes in the Company to OAO Minley. In September 2003, Harvest sold its interests in the Company to a company affiliated with OAO YUKOS (“YUKOS”).
Note 2: Basis of Presentation
The Company maintains its accounting records and prepares its statutory financial statements in accordance with the Regulations on Accounting and Reporting of the Russian Federation (“RAR”). The accompanying financial statements have been prepared from these accounting records and adjusted as necessary to comply with accounting principles generally accepted in the United States of America (“US GAAP”). The Company has a year ending 30 September for US GAAP reporting purposes.
In preparing the financial statements in conformity with US GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from such estimates.
Certain previously presented amounts have been reclassified to conform to the presentation adopted during the current period. These reclassifications had no impact on previously reported net income or stockholders’ equity.
Reporting and functional currency.The Russian Rouble is the functional currency (primary currency in which business is conducted) for the Company’s operations in the Russian Federation. The Company considers the US dollar as its reporting currency.
In November 2002, the International Practices Task Force concluded that Russia ceased being a highly inflationary economy as of 1 January 2003. As a result of the Task Force conclusion, the Company applied the guidance contained in Emerging Issues Task Force (“EITF”) No. 92-4 and EITF No. 92-8 as of 1 January 2003, which address changes in accounting when an economy ceases to be considered highly inflationary. As a result of the application of the guidance in EITF No. 92-4 and No. 92-8, as of 1 January 2003, the Company recognised a deferred tax liability of USD 8.1 million for temporary differences related to its property, plant and equipment and a corresponding amount as a cumulative translation adjustment as a separate component in stockholders’ equity.
Effective 1 January 2003, the measurement currency of the Company is the Russian Rouble. The transactions and balances in the accompanying financial statements have been translated into US dollars in accordance with the relevant provisions of Statement of Financial Accounting Standards (“SFAS”) No. 52,Foreign Currency Translation(“SFAS No. 52”). Consequently, assets and liabilities are translated at closing exchange rates. The statements of income and cash flows have been translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates have been included as a component of stockholders equity. The amount of such differences for the period beginning 1 January 2003 through 30 September 2003 was approximately USD 1.9 million. The exchange rates at 30 September 2003, and 30 September 2002, were 30.61 and 31.64, respectively, Russian Roubles to the US dollar.
Prior to 1 January 2003, transactions not already measured in US dollars were remeasured into US dollars in accordance with the relevant provisions of SFAS No. 52 as applied to hyperinflationary economies. Consequently, monetary assets and liabilities were translated at closing exchange rates and non-monetary items were translated at historic exchange rates and adjusted for any impairments. The statements of income and cash flows were translated using monthly average exchange rates. Translation differences resulting from the use of these exchange rates were included in the determination of net income and were included in exchange gains/losses in the accompanying statements of income through 31 December 2002.
1
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 2: Basis of Presentation (continued)
Inflation, exchange restriction and controls.Exchange restrictions and controls exist relating to converting Russian Roubles to other currencies. At present, the Russian Rouble is not a convertible currency outside the Russian Federation. Future movements in the exchange rates between the Russian Rouble and the US dollar will affect the carrying value of the Company’s Russian Rouble denominated assets and liabilities. Such movements may also affect the Company’s ability to realise non-monetary assets represented in US dollars in the accompanying financial statements. Accordingly, any translation of Russian Rouble amounts to US dollars should not be construed as a representation that such Russian Rouble amounts have been, could be, or will in the future be converted into US dollars at the exchange rate shown or at any other exchange rate. At 30 September 2003, the Company was required to sell 25% of its foreign currency receipts within the Russian Federation to the Central Bank for Russian Roubles. Such amounts are subject to certain deductions depending on debt payments on certain hard currency denominated borrowing agreements.
Note 3: Summary of Significant Accounting Policies
Cash and cash equivalents.Cash and cash equivalents include all highly liquid securities with original maturities of three months or less when acquired.
Accounts receivable.Accounts receivable are presented at net realisable value and include value-added and excise taxes which are payable to tax authorities upon collection of such receivables.
Inventories.Crude oil and petroleum products inventories are valued at the lower of cost, using the first-in-first out method, or net realisable value. Materials and supplies inventories are recorded at the lower of average cost or net realisable value.
Property, plant and equipment.The Company follows the full cost method of accounting for oil and gas properties. Under this method, all oil and gas property acquisition, exploration, and development costs including internal costs directly attributable to such activities are capitalized as incurred in the Company’s cost center (full cost pool), which is the Russian Federation. Payroll and other internal costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties as well as all other directly identifiable internal costs associated with these activities. Payroll and other internal costs associated with production operations and general corporate activities are expensed in the period incurred.
The full cost pool, including future development costs, estimated asset retirement obligations, net of prior accumulated depletion, is depleted using the unit-of-production method based upon actual production and estimates of proved reserve quantities. Proceeds from sales of oil and gas properties are credited to the full cost pool with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.
Pursuant to full cost accounting rules, capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves discounted at 10 percent; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. During 2003, the Company’s capitalized costs exceeded the ceiling limit resulting in an impairment of oil and gas properties. See Note 9 for additional information.
Pension and post-employment benefits.The Company’s mandatory contributions to the governmental pension scheme are expensed when incurred.
Revenue recognition.Revenue from the sale of crude oil and gas condensate are recognized when dispatched to customers and title has transferred.
2
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 3: Summary of Significant Accounting Policies (continued)
Income taxes.Deferred income tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, in accordance with SFAS No. 109,Accounting for Income Taxes. Deferred income tax assets and liabilities are measured using enacted tax rates in the years in which these temporary differences are expected to reverse. Valuation allowances are provided for deferred income tax assets when management believes it is more likely than not that the assets will not be realized.
Change in accounting principle. Effective 1 October 2002, the Company adopted Statement of Financial Accounting Standards No. 143,Accounting for Assets Retirement Obligations(“SFAS No. 143”). SFAS No. 143 requires entities to record the fair value of its asset retirement obligation as a liability in the period in which they are incurred and a corresponding increase in the carrying amount of the related long-lived asset.
SFAS No. 143 differs in several respects from the previous accounting method employed by the Company. Prior to the adoption of SFAS No. 143, the Company included estimated undiscounted asset retirement costs in its calculation for determining depletion expense. Under SFAS 143, the Company recognizes a liability for the fair value of an asset retirement obligation (“ARO”) in the period in which it is incurred, and capitalizes the associated asset retirement cost. In periods subsequent to initial measurement, the Company recognizes period-to-period changes in the liability for an ARO resulting from a) the passage of time and b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The Company’s asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities.
The cumulative effect of this change in accounting principle was a reduction in net income of USD 310 thousand, net of tax, which was recorded in the statement of income for the year ended 30 September 2003. The effect of adoption resulted in increases in property, plant and equipment and long-tem liabilities of USD 303 thousand and USD 613 thousand as of 1 October 2002, respectively.
The following table provides pro forma information as if SFAS No. 143 has been applied in previous periods:
| | | | | | | | | | | | | |
| | | Year ended | | Year ended | | Year ended |
Thousands of US dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
| Asset retirement obligations as of the beginning of the period | | | 613 | | | | 483 | | | | 358 | |
| Liabilities incurred for the period | | | 25 | | | | 56 | | | | 79 | |
| Accretion expense | | | 96 | | | | 75 | | | | 45 | |
| Asset retirement obligations as of the end of the period | | | 734 | | | | 613 | | | | 483 | |
| Net income for the period as reported | | | | | | | 3,885 | | | | 20,420 | |
| Pro-forma net income | | | | | | | 3,777 | | | | 20,358 | |
| | | |
| | | |
| | | |
| |
Recent accounting standards.FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities(“FIN 46R”), identifies certain off-balance sheet arrangements that meet the definition of a variable interest entity (“VIE”). FIN 46R requires consolidation of VIEs by primary beneficiaries and requires more extensive disclosures. FIN 46R is applicable to any VIE created after 1 February 2003. The Company does not expect the adoption of this interpretation will have any material effect on its financial position or results of operations.
3
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 4: Going Concern
During the years ended 30 September 2003 and 2002 the Company took steps to reduce its working capital deficit. These included the repayment of debt, the receipt of subordinated long-term loans from the Company’s stockholders and the repayment of accounts payable, primarily from additional borrowings from the European Bank for Reconstruction and Development (“EBRD”). However, as at 30 September 2003, and 30 September 2002, the current liabilities of the Company exceeded its current assets by USD 35,772 thousand and USD 35,266 thousand, respectively. Included in current liabilities, as at 30 September 2003 and 30 September 2002, are loans repayable to the EBRD of USD 30,000 thousand and USD 22,000 thousand, respectively. This debt has been reclassified as current because the Company is not in compliance with a loan facility covenant related to the required implementation of a new management information system, required by 1 May 2003. The loan facility also requires the Company to maintain a minimum working capital ratio. The Company was not in compliance with the required working capital ratio as of the interim reporting dates during the year ended 30 September 2003, however, it met the minimum required working capital ratio as of 30 September 2003 (see also Note 10). Under the terms of the loan facility the EBRD may declare the loan to be in default and can accelerate the maturity. There can be no assurance that the EBRD will not demand repayment of the loan.
During the year ended 30 September 2003, a substantial portion of the Company’s cash flow was utilised to pay accounts and taxes payable resulting in a reduction in capital expenditures for the year. In order to maintain or increase proved oil and gas reserves, the Company must make substantial capital expenditures in 2004 and subsequently. The Company’s cash flow from operations is dependent on the level of oil prices, which are historically volatile and are significantly impacted by the proportion of production that the Company can sell on the export market. Historically, the Company has supplemented its cash flow from operations with additional borrowings or equity capital and may continue to do so. Should oil prices decline for a prolonged period and should the Company not have access to additional capital, the Company would need to reduce its capital expenditures, which could limit its ability to maintain or increase production and, in turn, meet its debt service requirements. Asset sales and financing are restricted under the terms of debt agreements.
Management plans to further address the Company’s working capital deficit by resolving issues with the EBRD relating to its non compliance with the loan covenants and by reducing certain capital expenditures and funding its 2004 cash requirements with cash flows from existing producing properties and its development drilling program. Management is in the process of implementing the required management information system and expects to have implemented this system during the 2004 reporting year. The accompanying financial statements do not include any adjustments that might result if the Company were unable to continue as a going concern.
Note 5: Cash and Cash Equivalents
Included in cash and cash equivalents as at 30 September 2003, and 2002, respectively, are Russian Rouble denominated amounts totaling RR 19.7 million (USD 643 thousand) and RR 18.3 million (USD 578 thousand).
Restricted cash consists of deposits with lending institutions to pay interest and principal as discussed in Note 10. As at 30 September 2003, the amount of restricted cash was USD 1,217 thousand (2002: USD 1,469 thousand). These accounts are maintained in US Dollar denominated accounts located outside Russia.
Note 6: Financial Instruments
Fair values.The estimated fair values of financial instruments are determined with reference to various market information and other valuation methodologies as considered appropriate, however considerable judgment is required in interpreting market data to develop these estimates. Accordingly, the estimates are not necessarily indicative of the amounts that the Company could realize in a current market transaction. The methods and assumptions used to estimate fair value of each class of financial instrument are presented below.
Cash and cash equivalents, accounts receivable and accounts payable.The carrying amount of these items are a reasonable approximation of their fair value.
Short-term and long-term debt. Loan arrangements have both fixed and variable interest rates that reflect the currently available terms and conditions for similar debt. The carrying value of this debt is a reasonable approximation of its fair value.
4
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 6: Financial Instruments (continued)
Credit risk. A significant portion of the Company’s accounts receivable are from domestic and foreign customers, and advances are made to domestic suppliers. Although collection of these amounts could be influenced by economic factors affecting these entities, management believes there is no significant risk of loss to the Company beyond the provisions already recorded, provided that the economic situation in the Russian Federation does not deteriorate (Note 16).
Note 7: Accounts Receivable and Advances to Suppliers
| | | | | | | | | |
Thousands of US dollars
| | 30 September 2003
| | 30 September 2002
|
| Trade accounts receivable | | | 1,531 | | | | 1,387 | |
| Recoverable value-added tax | | | 4,227 | | | | 3,515 | |
| Advances to suppliers | | | 1,286 | | | | 1,193 | |
| Advances to customs | | | 117 | | | | 137 | |
| Other receivables | | | — | | | | 76 | |
| | | |
| | | |
| |
Total accounts receivable and advances to suppliers | | | 7,161 | | | | 6,308 | |
| | | |
| | | |
| |
Accounts receivables are presented net of an allowance for doubtful accounts of USD 147 thousand and USD 70 thousand at 30 September 2003 and 2002, respectively.
Note 8: Inventories
| | | | | | | | | |
Thousands of US Dollars
| | 30 September 2003
| | 30 September 2002
|
| Materials and supplies | | | 7,442 | | | | 6,905 | |
| Crude oil | | | 576 | | | | 296 | |
| | | |
| | | |
| |
Total inventories | | | 8,018 | | | | 7,201 | |
| | | |
| | | |
| |
Note 9: Oil and Gas Producing Properties
| | | | | | | | | |
Thousands of US dollars
| | 30 September 2003
| | 30 September 2002
|
| Oil and gas producing properties, cost | | | 302,214 | | | | 278,459 | |
| Accumulated depletion and impairment | | | (212,745 | ) | | | (92,470 | ) |
| | | |
| | | |
| |
Oil and gas producing properties, net book value | | | 89,469 | | | | 185,989 | |
| | | |
| | | |
| |
The Company’s oil and gas fields are situated on land belonging to the Government of the Russian Federation. The Company obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Licenses will expire in September 2018 for the North Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the licenses may be extended over the economic life of the lease at the Company’s option. Management intends to extend such licenses for properties that are expected to produce subsequent to their expiry dates. Estimates of proved reserves extending past 2018 represent approximately 9 percent of total proved reserves.
At 31 December 2002 and at 31 March 2003, the Company’s capitalized costs for oil and gas producing properties exceeded its full cost accounting ceiling limitation. The Company’s ceiling limitation decreased primarily because of a decline in the Company’s average realized price it received for its oil at those dates. As a result the Company recorded impairments of its oil and gas producing properties in the aggregate amount of USD 95 million (excluding a deferred income tax benefit of USD 7.6 million); this impairment was recorded as an impairment expense in the statement of income for the year ended 30 September 2003.
5
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 10: Long-term Debt
| | | | | | | | | |
Thousands of US dollars
| | 30 September 2003
| | 30 September 2002
|
| EBRD | | | 30,000 | | | | 22,000 | |
| IMB | | | — | | | | 550 | |
| OAO Minley | | | 5,000 | | | | 5,000 | |
| YUKOS | | | 2,500 | | | | — | |
| Harvest Natural Resources | | | — | | | | 2,500 | |
| Less: current portion | | | (37,500 | ) | | | (22,550 | ) |
| | | |
| | | |
| |
Total long-term debt | | | — | | | | 7,500 | |
| | | |
| | | |
| |
EBRD loan.At 30 September 2003, the outstanding balance of loans with the EBRD totaled USD 30 million. On 23 September 2002, the Company signed an amended loan agreement with the EBRD that increased the maximum amount that could be drawn down under the facility with the EBRD to USD 50 million. Under the loan agreement, the use of loan proceeds is restricted to the repayment of accounts payable and development of oil and gas reserves. This loan facility is to be repaid such that the loan balance may not exceed set amounts at certain dates in the future. The interest rate under the loan agreement is linked to the London interbank offer rate (“LIBOR”) and an agreed upon margin. The Company must hold as restricted cash a) principal and interest to be paid at the next repayment date and b) 30 percent of the total of principal and interest to be paid at the following repayment date.
LIBOR interest rates ranged from 1.12 percent to 1.84 percent in 2003 (2002: 1.84 percent to 3.5 percent, 2001: 3.5 percent to 6.94 percent). The annual weighted average interest rates on these loans varied between 5.09 percent and 5.43 percent for the year ended 30 September 2003 (2002: 8.59 percent and 11.71 percent, 2001: 14.93 percent to 15.17 percent). The loan is collaterized by the Company’s immovable assets and crude oil export contracts.
The EBRD loan agreement includes certain covenants which include, among other things, the maintenance of financial ratios. If the Company fails to meet these requirements for two concecutive quarters it will result in an event of default whereby the EBRD may, at its option, demand payment of the outstanding principal and interest. As dicussed in Note 4, as of 31 December 2002, 31 March 2003 and 30 June 2003 the Company was in violation of the minimum working capital ratio covenant. As of 30 September 2003, the minimum working capital ratio as defined in the loan facility exceeds the covenant requirements. Additionally, the Company has not completed its implementation of a management information system as required under the terms of the loan. Due to these loan convenant violations, the Company has classified the EBRD debt as a current liability.
In addition, while in default of EBRD covenants, the Company may not declare or pay any dividend, make any distribution on its charter capital, purchase, or redeem any shares of the charter capital of the Company, nor make any payment of principal or interest on subordinated shareholder loans or make any other payment or distribution to any stockholder or any affiliate of any stockholder.
As part of the sale of Harvest’s interest in the Company to YUKOS, as described in Note 1, YUKOS assumed Harvest’s stockholder loan.
Loans from OAO Minley and YUKOS are subordinated, unsecured and repayable commencing from January 2004. Interest rates are 2 percent for the Minley loan, and LIBOR for the YUKOS loan, to January 2004. Repayment of the subordinated loans are subject to approval from the EBRD. If approval is not received, the terms of the loan agreements are not considered to be violated. After January 2004, the interest rates on the YUKOS loan increases to 8 percent for the remainder of 2004, and 12 percent from 2005 onwards.
6
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 10: Long-term Debt (continued)
While the Company remains in violation of its EBRD loan convenants, further borrowings under the facility are at the sole discretion of the EBRD. The maximum loan facility available under the terms of the EBRD loan and the related aggregate maturities are as follows:
| | | | | |
/s/ Stephen D. Chesebro’Stephen D. Chesebro’ | | Maximum loan facility |
Thousands of US dollars
| | outstanding
|
30 September 2003 to 27 January 2004 | | | 50,000 | |
27 January 2004 to 27 July 2004 | | | 41,667 | |
27 July 2004 to 27 January 2005 | | | 33,333 | |
27 January 2005 to 27 July 2005 | | | 25,000 | |
27 July 2005 to 27 January 2006 | | | 16,667 | |
27 January 2006 to 27 January 2007 | | | 8,333 | |
Thereafter | | | — | |
| | | |
Chairman of the Board and Director | |
The aggregate maturities of long-term debt outstanding at 30 September 2003 are as follows:
| | | | | |
Thousands of US dollars
/s/ John U. ClarkeJohn U. Clarke | | | | Director |
Year ended 30 September 2004 | | | 7,500 | |
Year ended 30 September 2005 | | | 5,000 | |
Year ended 30 September 2006 | | | 8,333 | |
Year ended 30 September 2007 | | | 8,333 | |
Year ended 30 September 2008 | | | 8,333 | |
| | |
| |
Note 11: Taxes Payable
| | | | | | | | | |
Thousands of US dollars
| | 30 September 2003
| | 30 September 2002
|
| Value added tax | | | — | | | | 1,445 | |
| Income tax | | | 3,777 | | | | 1,176 | |
| Royalty | | | — | | | | 896 | |
| Mineral restoration tax | | | — | | | | 152 | |
| Road users tax | | | — | | | | 642 | |
| Unified production tax | | | 1,552 | | | | 6,703 | |
| Property taxes | | | 586 | | | | 1,121 | |
| Penalties and interest | | | 1,784 | | | | 219 | |
| Other taxes | | | 159 | | | | — | |
| | | |
| | | |
| |
Total taxes payable | | | 7,858 | | | | 12,354 | |
| | | |
| | | |
| |
7
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 12: Contributed Capital
Capital contributions are as follows:
| | | | | | | | | |
Thousands of US dollars
| | 30 September 2003
| | 30 September 2002
|
| OAO Minley | | | 54,733 | | | | 54,733 | |
| YUKOS | | | 27,785 | | | | — | |
| Harvest Natural Resources | | | — | | | | 27,785 | |
| | | |
| | | |
| |
Total contributed capital | | | 82,518 | | | | 82,518 | |
| | | |
| | | |
| |
All capital contributions have been made since inception in accordance with the Company’s Foundation Document.
Reserves available for distribution to shareholders are based on the statutory accounting reports of the Company, which are prepared in accordance with Regulations on Accounting and Reporting of the Russian Federation and differ from US GAAP. Russian legislation identifies the basis of distribution as net income. For 2002, the current year statutory net income for the Company as reported in the annual statutory accounting reports was RR 772 million (2001: RR 551 million). However, current legislation and other statutory laws and regulations dealing with distribution rights are open to legal interpretation and, consequently, actual distributable reserves may differ from the amount disclosed. The Company cannot distribute capital while in default of its EBRD loan facility obligations (Note 10).
Note 13: Revenues
Revenues for the years ended 30 September 2003, 2002 and 2001, consisted of the following:
| | | | | | | | | | | | | |
Thousand of US dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
| Crude oil — export (Europe and CIS) | | | 51,949 | | | | 47,751 | | | | 83,889 | |
| Crude oil — domestic | | | 28,599 | | | | 40,778 | | | | 10,900 | |
| Gas condensate — domestic | | | 1,176 | | | | — | | | | — | |
| Refined products — domestic | | | — | | | | 2,764 | | | | 6,231 | |
| Other operating revenues | | | 583 | | | | 305 | | | | 139 | |
| | | |
| | | |
| | | |
| |
Total sales and other operating revenues | | | 82,307 | | | | 91,598 | | | | 101,159 | |
| | | |
| | | |
| | | |
| |
Note 14: Taxes
Presented below is a reconciliation between the provision for income taxes and taxes determined by applying the statutory tax rate as applied in the Russian Federation to income before income taxes.
| | | | | | | | | | | | | |
Thousand of US dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
| Income (loss) before income taxes | | | (87,691 | ) | | | 4,187 | | | | 27,171 | |
| | | |
| | | |
| | | |
| |
| Theoretical income tax expense (benefit) at statutory rate (24% in 2002 and 2003; 35% in 2001) | | | (21,046 | ) | | | 1,005 | | | | 9,509 | |
| Increase (reduction) due to: | | | | | | | | | | | | |
| Change in valuation allowance | | | 17,192 | | | | 80 | | | | 1,810 | |
| Non-deductible expenses | | | 1,860 | | | | 2,894 | | | | 2,693 | |
| Investment tax credits | | | (593 | ) | | | (5,348 | ) | | | (6,821 | ) |
| Change in statutory tax rate | | | — | | | | 595 | | | | (750 | ) |
| Tax penalties and interest | | | 442 | | | | 1,135 | | | | 517 | |
| Other | | | (972 | ) | | | (59 | ) | | | (207 | ) |
| | | |
| | | |
| | | |
| |
Total income tax expense (benefit) | | | (3,117 | ) | | | 302 | | | | 6,751 | |
| | | |
| | | |
| | | |
| |
8
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 14: Taxes (continued)
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for statutory tax purposes. Net deferred tax assets are comprised of the following, at 30 September 2003 and 2002:
| | | | | | | | | |
Thousand of US dollars
| | 30 September 2003
| | 30 September 2002
|
| Inventories | | | (313 | ) | | | 93 | |
| Accounts receivable | | | 121 | | | | 258 | |
| Accounts payable and accrued liabilities | | | 1,205 | | | | 430 | |
| Losses carried forward | | | 966 | | | | 2,502 | |
| Property, plant and equipment | | | 4,989 | | | | 4,810 | |
| | | |
| | | |
| |
| Total deferred tax assets | | | 6,968 | | | | 8,093 | |
| Less: Valuation allowance | | | (6,002 | ) | | | (5,591 | ) |
| | | |
| | | |
| |
Net deferred tax asset | | | 966 | | | | 2,502 | |
| | | |
| | | |
| |
Losses carried forward represent those losses for tax purposes which, according to legislation, the Company is permitted to offset against future taxable earnings in the periods up to 2008, and is subject to limitations of no more than 30% of the Company’s tax liabilities for the tax reporting period.
As at 30 September 2003, management of the Company have assessed the recoverability of the Company’s deferred tax assets and believe that it will be able to realise the tax losses carried forward. Accordingly, the Company has provided a valuation allowance as at 30 September 2003 and 2002, of USD 6,002 thousand and USD 5,591 thousand, respectively, against the remaining deferred tax assets.
Principal movements in the valuation allowance for deferred income tax assets (“DTA”) during the year ended 30 September 2003 are as follows:
| | | | | |
Millions of US dollars
/s/ H. H. HardeeH. H. Hardee | | | | Director |
| | | | |
Valuation allowance, beginning of period/s/ Patrick M. MurrayPatrick M. Murray | | | 5.6 | |
Increase related to DTA resulting from the December ceiling test writedown | | | 12.0 | |
Net other increase in DTA movements during the December quarter | | | 1.0 | |
Decrease due to application of EITF No. 92-4 and No. 92-8 effective 1 January 2003 | | | (16.8 | ) |
Increase relating to DTA resulting from the March ceiling test writedown | | | 3.2 | |
Net other increase in DTA movements | | | 1.0 | Director |
| | | |
| |
Valuation allowance, end of period/s/ J. Michael StinsonJ. Michael Stinson | | | 6.0 | |
| | | |
| Director |
As a result of the application of EITF No. 92-4 and No. 92-8, the valuation allowance related to property, plant and equipment was reduced to zero and a deferred tax liability of USD 8.1 million recorded on 1 January 2003 (Note 2), with no effect on income as the adjustment was recorded as part of the currency translation adjustment as of 1 January 2003. A subsequent ceiling test writedown in March resulted in the recognition of an additional deferred tax asset of USD 10.8 million of which USD 7.6 million and USD 3.2 million were credited as a deferred tax benefit and an increase to the DTA valuation allowance, respectively.
Deferred income tax assets are classified as follows:
| | | | | | | | | |
Thousands of US dollars
| | 30 September 2003
| | 30 September 2002
|
| Deferred income tax, current | | | 966 | | | | 1,806 | |
| Deferred income tax, non-current | | | — | | | | 696 | |
| | | |
| | | |
| |
Total net deferred tax asset | | | 966 | | | | 2,502 | |
| | | |
| | | |
| |
9S-29
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTSSCHEDULE II
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(expressed in US Dollars except as indicated)thousands)
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Additions | | | | |
| | | Balance at | | | | | | Charged | | Deductions | | Balance |
| | | Beginning | | Charged to | | to Other | | From | | at End of |
| | | of Year | | Income | | Accounts | | Reserves | | Year |
At December 31, 2006 | | | | | | | | | | | | | | | | | | | | |
| Amounts deducted from applicable assets | | | | | | | | | | | | | | | | | | | | |
| Accounts receivable | | $ | 2,757 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,757 | |
| Deferred tax valuation allowance | | | 27,363 | | | | 5,446 | | | | | | | | | | | | 32,809 | |
| Investment at cost | | | 1,350 | | | | — | | | | — | | | | — | | | | 1,350 | |
At December 31, 2005 | | | | | | | | | | | | | | | | | | | | |
| Amounts deducted from applicable assets | | | | | | | | | | | | | | | | | | | | |
| Accounts receivable | | $ | 2,757 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,757 | |
| Deferred tax valuation allowance | | | 40,492 | | | | (13,129 | ) | | | — | | | | — | | | | 27,363 | |
| Investment at cost | | | 1,350 | | | | — | | | | — | | | | — | | | | 1,350 | |
At December 31, 2004 | | | | | | | | | | | | | | | | | | | | |
| Amounts deducted from applicable assets | | | | | | | | | | | | | | | | | | | | |
| Accounts receivable | | $ | 3,355 | | | $ | — | | | $ | — | | | $ | 598 | | | $ | 2,757 | |
| Deferred tax valuation allowance | | | 48,365 | | | | (7,873 | ) | | | — | | | | — | | | | 40,492 | |
| Investment at cost | | | 1,350 | | | | — | | | | — | | | | — | | | | 1,350 | |
Note 14: Taxes (continued)
Taxes other than income tax.The Company is subject to a number of taxes other than on income which are detailed below.
| | | | | | | | | | | | | |
Thousands of US dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
| Export duties | | | 8,464 | | | | 5,376 | | | | 10,922 | |
| Excise tax | | | — | | | | 535 | | | | 1,548 | |
| Royalty | | | — | | | | 2,254 | | | | 4,867 | |
| Mineral restoration tax | | | 377 | | | | 885 | | | | 4,596 | |
| Road users tax | | | 203 | | | | 860 | | | | 1,427 | |
| Unified production tax | | | 19,056 | | | | 14,221 | | | | — | |
| Property taxes | | | 2,263 | | | | 1,994 | | | | 1,424 | |
| Taxes recovery | | | (7,017 | ) | | | — | | | | — | |
| Other taxes | | | 2,279 | | | | 1,532 | | | | 1,227 | |
| | | |
| | | |
| | | |
| |
Total taxes other than income tax | | | 25,625 | | | | 27,657 | | | | 26,011 | |
| | | |
| | | |
| | | |
| |
Beginning 1 January 2002, mineral restoration tax, royalty tax and excise tax on crude oil production were abolished and replaced by the unified natural resources production tax. From 1 January 2004 through 31 December 2006, the base rate for the unified natural resources production tax is set at RR 347 per metric ton of crude oil produced, and is to be adjusted depending on the market price of Urals blend and the RR/USD exchange rate. The tax becomes nil if the Urals blend price falls to or below USD 8.00 per barrel. From 1 January 2007, the unified natural resources production tax rate is set by law at 16.5 percent of crude oil revenues recognized by the Company based on Tax Regulations of the Russian Federation.
During the year ended 30 September 2003, the Company pursued its claim of overpayment of mineral restoration taxes (MRT) paid during the period from 1999 to 2001 of approximately RR 211 million (USD 7.0 million), plus approximately RR 4 million (USD 0.1 million) in related penalties paid. During the year, the regional courts ruled in favour of the Company and, accordingly, the Company and the tax authorities agreed to offset the amounts awarded against the Company’s unified production taxes payable.
Note 15: Related Party Transactions
As of 30 September 2003 and 2002, the Company had the following balances with its stockholders. These balances are included in the balance sheet within accounts receivable, accounts payable and long-term debt as appropriate.
| | | | | | | | | |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
|
Accounts receivable | | | | | | | | |
| Purneftegasgeologia and affiliated entities | | | 19 | | | | 63 | |
Accounts payable | | | | | | | | |
| Purneftegasgeologia and affiliated entities | | | 183 | | | | 574 | |
| YUKOS | | | 2,111 | | | | — | |
| Harvest Natural Resources | | | — | | | | 3,354 | |
| Purneftegas and affiliated entities | | | — | | | | 22 | |
Long-term debt | | | | | | | | |
| Harvest Natural Resources | | | — | | | | 2,500 | |
| YUKOS | | | 2,500 | | | | — | |
| Minley | | | 5,000 | | | | 5,000 | |
10S-30
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 15: Related Party Transactions (continued)
Harvest Natural Resources/YUKOS.During 2003 and 2002, Harvest provided insurance on behalf of the Company and personnel services
Index 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
Exhibits
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 16: Commitments and Contingent Liabilities (continued)
Oilfield licenses.The Company is subject to periodic reviews of its activities by governmental authorities with respect to the requirements of its oilfield licenses. Management of the Company correspond with governmental authorities to agree on remedial actions necessary to resolve any findings resulting from these reviews. Failure to comply with the terms of a license could result in fines, penalties or license limitation, suspension or revocation. The Company’s management believes any issues of non-compliance will be resolved through negotiations or corrective actions without any materially adverse effect on the Company’s financial position or results of operations.
Legal contingencies.The Company is claiming additional deductions relating to the fiscal periods from 1999 to 2001 amounting to approximately RR 330 million (USD 10.8 million). Management believe these deductions are permitted for companies operating in the northern regions of the Russian Federation and also deductions for certain interest paid during that period. Although the Company was successful in the initial hearing before the courts, the tax authorities have continued to challenge the Company’s position. As at 30 September 2003, the Company has not recorded any benefit relating to the above claims.
The Company is the named defendant in a number of lawsuits as well as the named party in numerous other proceedings arising in the ordinary course of business. While the outcomes of such contingencies, lawsuits or other proceedings cannot be determined at present, management believes that any resulting liabilities will not have a materially adverse effect on the operating results or the financial position of the Company.
Insurance.At 30 September 2003 and 2002, the Company held limited insurance policies in relation to its assets and operations, or in respect of public liability or other insurable risks. Since the absence of insurance alone does not indicate that an asset has been impaired or a liability incurred, no provision has been made in the financial statements for unspecified losses.
12
Exhibits:
LLC GEOILBENT
Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)
(expressed in thousands US Dollars except as indicated)
Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)
In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS No. 69”), this section provides supplemental information on the Company’s oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities:
| | | | | | | | | | | | | |
| | | Year ended | | Year ended | | Year ended |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
| Development costs | | | 10,217 | | | | 25,290 | | | | 33,774 | |
| Exploration costs | | | 3,040 | | | | 1,465 | | | | 6,100 | |
| | | |
| | | |
| | | |
| |
Total costs incurred in oil and natural gas acquisition, exploration, and development activities | | | 13,257 | | | | 26,755 | | | | 39,874 | |
| | | |
| | | |
| | | |
| |
TABLE II — Capitalized costs related to oil and natural gas producing activities:
| | | | | | | | | |
| | | As at | | As at |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
|
| Proved property costs | | | 302,214 | | | | 277,659 | |
| Costs excluded from amortisation | | | — | | | | 800 | |
| Oilfield inventories | | | 7,442 | | | | 6,905 | |
| Less accumulated depletion and impairment | | | (212,745 | ) | | | (92,470 | ) |
| | | |
| | | |
| |
Total capitalised costs related to oil and natural gas producing activities | | | 96,911 | | | | 192,894 | |
| | | |
| | | |
| |
TABLE III — Results of operations for oil and natural gas producing activities:
In accordance with SFAS 69, results of operations for oil and natural gas producing activities do not include general corporate overhead and monetary effects, nor their associated tax effects. Income tax is based on statutory rates for the year, adjusted for tax deductions, tax credits and allowances.
| | | | | | | | | | | | | |
| | | Year ended | | Year ended | | Year ended |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
| Oil and natural gas sales | | | 81,987 | | | | 91,291 | | | | 100,768 | |
| Expenses: | | | | | | | | | | | | |
| Operating, selling and distribution expenses and taxes other than on income | | | 47,319 | | | | 49,713 | | | | 47,302 | |
| Depletion and amortization | | | 18,278 | | | | 27,168 | | | | 14,918 | |
| Impairment of oil and gas properties | | | 95,000 | | | | — | | | | — | |
| Income tax expense | | | 6,098 | | | | 5,750 | | | | 11,006 | |
| Total expenses | | | 166,695 | | | | 82,631 | | | | 73,226 | |
| | | |
| | | |
| | | |
| |
Results of operations from oil and natural gas producing activities | | | (84,708 | ) | | | 8,660 | | | | 27,542 | |
| | | |
| | | |
| | | |
| |
13
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)
TABLE IV — Quantities of oil and natural gas reserves
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions.
The Company’s oil and gas fields are situated on land belonging to the Government of the Russian Federation. The Company obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Licenses will expire in September 2018 for the North Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the licenses may be extended over the economic life of the lease at the Company’s option. Management intends to extend such licenses for properties that are expected to produce subsequent to their expiry dates. Estimates of proved reserves extending past 2018 represent approximately 9 percent of total proved reserves.
The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and the Company considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.
Proved developed reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed non producing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.
Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.
Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for proved undeveloped reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.
Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.
The evaluations of the oil and natural gas reserves were prepared by Ryder-Scott Company, independent petroleum engineers.
14
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)
| | | | | | | | | | | | | |
| Proved reserves-crude oil, | | | | | | |
| condensate and natural gas | | Year ended | | Year ended | | Year ended |
liquids (MBbls)
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
Proved reserves beginning of year | | | 74,575 | | | | 87,259 | | | | 95,924 | |
| Revisions of previous estimates | | | 1,580 | | | | (10,163 | ) | | | (16,454 | ) |
| Extensions, discoveries and improved recovery | | | 2,829 | | | | 4,391 | | | | 12,974 | |
| Production | | | (5,712 | ) | | | (6,912 | ) | | | (5,185 | ) |
| | | |
| | | |
| | | |
| |
Proved reserves, end of year | | | 73,272 | | | | 74,575 | | | | 87,259 | |
| | | |
| | | |
| | | |
| |
Proved developed reserves | | | 35,344 | | | | 38,824 | | | | 46,052 | |
| | | |
| | | |
| | | |
| |
TABLE V — Standardized measure of discounted future net cash flows related to proved oil and natural gas reserve quantities
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
| | | | | | | | | | | | | |
| | | Year ended | | Year ended | | Year ended |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 20
|
| Future cash inflow | | | 1,416,343 | | | | 1,381,874 | | | | 1,277,494 | |
| Future production costs | | | (676,419 | ) | | | (599,277 | ) | | | (739,221 | ) |
| Future development costs | | | (107,841 | ) | | | (119,725 | ) | | | (108,882 | ) |
| | | |
| | | |
| | | |
| |
| Future net revenue before income taxes | | | 632,083 | | | | 662,872 | | | | 429,391 | |
| 10% annual discount for estimated timing of cash flows | | | (293,965 | ) | | | (318,079 | ) | | | (190,788 | ) |
| | | |
| | | |
| | | |
| |
| Discounted future net cash flows before income taxes | | | 338,118 | | | | 344,793 | | | | 238,603 | |
| Future income taxes, discounted at 10% per annum | | | (68,126 | ) | | | (71,442 | ) | | | (30,815 | ) |
| | | |
| | | |
| | | |
| |
Standardized measure of discounted future net cash flows | | | 269,992 | | | | 273,351 | | | | 207,788 | |
| | | |
| | | |
| | | |
| |
15
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)
TABLE VI — Changes in the standardized measure of discounted future net cash flows from proved reserves
| | | | | | | | | | | | | |
| | | Year ended | | Year ended | | Year ended |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
Present value at beginning of period | | | 273,351 | | | | 207,788 | | | | 337,426 | |
| Sales of oil and natural gas, net of related costs | | | (60,030 | ) | | | (69,541 | ) | | | (54,015 | ) |
| Revisions to estimates of proved reserves: | | | | | | | | | | | | |
| Net changes in prices, development and production costs | | | (16,242 | ) | | | 225,132 | | | | (107,356 | ) |
| Quantities | | | 9,346 | | | | (29,432 | ) | | | (71,709 | ) |
| Extensions, discoveries and improved recovery, net of future costs | | | 3,663 | | | | 5,974 | | | | 55,197 | |
| Accretion of discount | | | 34,479 | | | | 23,862 | | | | 41,224 | |
| Net change of income taxes | | | 3,316 | | | | 3,367 | | | | 43,994 | |
| Development costs incurred | | | 13,257 | | | | 26,468 | | | | 37,953 | |
| Changes in timing and other | | | 8,852 | | | | (120,267 | ) | | | (74,926 | ) |
| | | |
| | | |
| | | |
| |
Present value at end of period | | | 269,992 | | | | 273,351 | | | | 207,788 | |
| | | |
| | | |
| | | |
| |
16
EXHIBIT INDEX
| | | |
Exhibits | | Description of Exhibit |
| |
|
| 3.1 | | Amended and Restated Certificate of Incorporation filed September 9, 1988Incorporation. (Incorporated by reference to Exhibit 3.13.1(i) to our Registration Statement (RegistrationForm 10-Q filed on August 13, 2002, File No. 33-26333)1-10762.). |
|
| | | |
| 3.2 | | Amendment to Certificate of Incorporation filed June 7, 1991 (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-39214)). |
| | |
3.3 | | Amended and Restated Bylaws as of December 11, 2003.April 6, 2006. (Incorporated by reference to Exhibit 3.2 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.) |
| |
| | |
| 4.1 | | Form of Common Stock Certificate (Previously filed as an exhibitCertificate. (Incorporated by reference to the exhibits to our S-1 Registration Statement Form S-1 (Registration No. 33-26333).). |
| |
| | |
| 4.2 | | Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.) |
| |
| | |
| 4.3 | | Second Amended and Restated Rights Agreement, dated as of April 15, 2005, between Benton OilHarvest Natural Resources, Inc. and Gas Company and First InterstateWells Fargo Bank, Rights Agent dated April 28, 1995.N.A. (Incorporated by reference to Exhibit 4.14.3 to our Form 10-Q filed on August 13, 2002,April 29, 2005, File No. 1-10762.) |
| | | |
10.1 | | Form of Employment Agreements (Exhibit 10.19)(Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)). |
| | | |
10.210.1 | | Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission—Exhibit 10.25)(Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-52436)). |
| | |
Exhibits | | Description of Exhibit |
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10.3 | | Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to an aggregate of $115,000,000 principal amount of 9 3/8 percent Senior Notes due 2007Commission. (Incorporated by reference to Exhibit 10.1the exhibits to our Registration Statement Form 10-Q for the quarter ended September 30, 1997, FileS-1 (Registration No. 1-10762)33-52436).) |
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10.4 | | Note payable agreement dated March 8, 2001 between Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita Pipeline (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762). |
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10.5 | | Change of Control Severance Agreement effective May 4, 2001 (Incorporated by reference to Exhibit 10.26 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.). |
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10.610.3 | | Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.). |
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10.7 | | First Amendment to Change of Control Severance Plan effective June 5, 2001 (Incorporated by reference to Exhibit 10.31 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.). |
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10.8 | | Sale and Purchase Agreement dated February 27, 2002 between Benton Oil and Gas Company and Sequential Holdings Russian Investors Limited regarding the sale of Benton Oil and Gas Company’s 68 percent interest in Arctic Gas Company. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on March 28, 2002, File No. 1-10762.) |
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10.910.5 | | 2001 Long Term Stock Incentive PlanPlan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).). |
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10.1010.6 | | Addendum No. 2 to Operating ServicesService Agreement Monagas SUR dated 19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
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10.1110.7† | | Bank Loan Agreement between Banco Mercantil, C.A. and Benton-Vinccler C.A. dated October 1, 2002.Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 10.54.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).) |
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| 10.8† | | Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
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| 10.9† | | Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
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| 10.10† | | Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
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| 10.11† | | Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
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| 10.12 | | The Transitory Agreement between Harvest Natural Resources, Inc. and PDVSA Petroleo S.A., dated August 4, 2005. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 8, 2002,October 27, 2005, File No. 1-10762.) |
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10.12 | | Guaranty issued by Harvest Natural Resources, Inc. dated September 26, 2002. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
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| 10.13† | | Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Peter J. Hill. (Incorporated by reference to Exhibit 10.10 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
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10.14 | | Employment Agreement dated August 1, 2002September 12, 2005 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.1110.2 to our Form 10-Q filed on November 8, 2002,October 27, 2005, File No. 1-10762.) |
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10.1510.14† | | Employment Agreement dated August 1, 2002September 12, 2005 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.1210.3 to our Form 10-Q filed on November 8, 2002,October 27, 2005, File No. 1-10762.) |
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10.1610.15† | | Employment Agreement dated August 1, 2002September 12, 2005 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
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| 10.16† | | Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
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| 10.17† | | Employment Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
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| 10.18† | | Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
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| 10.19† | | Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
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| 10.20† | | Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
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| 10.21† | | Employment Agreement dated February 10, 2006 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.1310.1 to our Form 10-Q filed on November 8, 2002,April 20, 2006, File No. 1-10762.) |
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| | 10.22 | | Memorandum of Understanding dated March 31, 2006, between Corporación Venezolana del Petroleo, S.A., PDVSA Petroleo, S.A. and Harvest Vinccler, C.A. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.) |
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10.17 | 10.23 | | Sale and PurchaseHarvest Natural Resources 2006 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on June 1, 2006 [Registration Statement No. 333-134630].) |
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| 10.24 | | Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
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| 10.25 | | Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
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| 10.26 | | Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
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| 10.27 | | Stock Unit Award Agreement dated September 26, 2003,15, 2005 between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regardingJames A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
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| 10.28 | | Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
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| 10.29 | | Note Payable agreement dated September 28, 2006 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. Banco Universal related to a principal amount of 105 billion Bolivars with interest at 10.02 percent, for financing of the sale of our 34 percent minority equity investment in LLC Geoilbent.SENIAT assessments. (Incorporated by reference to Exhibit 10.1 to our Form 8-K10-Q filed on October 10, 2003,26, 2006, File No. 1-10762.) |
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10.1810.30 | | Employment AgreementNote Payable agreement dated November 17, 2003October 3, 2006 between Harvest Natural Resources, Inc. |
| | Vinccler, C.A. and Banco Mercantil, C.A. Banco Universal related to a principal amount of 20 billion Bolivars with interest at 10.02 percent, for financing of the SENIAT assessments. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 26, 2006, File No. 1-10762.) |
Exhibits | | Description of Exhibit |
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| | 10.31 | | Amendment to Original Memorandum of Understanding dated August 16, 2006, between Corporación Venezolana del Petroleo, S.A. and Karl L. Nesselrode.Harvest Vinccler, C.A. (Incorporated by reference to Appendix C to our Definitive Proxy filed on November 6, 2006, File No. 1-10762.) |
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| | 10.32 | | Note Payable agreement dated November 20, 2006 between Harvest Vinccler, C.A. and Banesco Banco Universal C.A. related to a principal amount of 120 billion Bolivars with interest at 10.0 percent, for refinancing of the SENIAT assessments and operating requirements. |
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| 10.33 | | Form of 2006 Long Term Incentive Plan Stock Option Agreement – Five Year Vesting, Seven Year Term. |
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| 21.1 | | List of subsidiaries. |
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| 23.1 | | Consent of PricewaterhouseCoopers LLP -– Houston |
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23.2 | | Consent of ZAO PricewaterhouseCoopers Audit - Moscow |
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23.323.2 | | Consent of Ryder Scott Company, LP |
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| 31.1 | | Certification of the Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002 executed by James A. Edmiston, President and Chief Executive Officer. |
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| 31.2 | | Certification of the Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer. |
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| 32.1 | | CertificationsCertification accompanying the annual reportAnnual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002 executed by James A. Edmiston, President and Chief Executive Officer. |
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| 32.2 | | Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer. |
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| † | | Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K. |
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