UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
(Mark One)
| | | |
| 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, 2004 |
| | 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) |
| 1177 Enclave Parkway, Suite 300 | | |
| Houston, Texas | | 77077 |
| (Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code:
(281) 899-570015835 Park Ten Place Drive, Suite 115
Houston, Texas 77084
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| | | |
Title of each class | | Name of each exchange on which registered |
| Common Stock, $.01 Par Value | | NYSE |
Securities registered pursuant to Section 12(g) of the Act:
| | | |
Title of each class | | Name of each exchange on which registered |
| None | | None |
Indicate by check mark whether the registrant 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
þ No
oIndicate 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.
oþIndicate 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
þo No
oþState the
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 30,
2004: $535,652,892.2006 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
February 11, 2005,March 2, 2007, shares outstanding:
37,596,464.37,536,523.
DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant’s Proxy Statement for the 20052007 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.
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 our concentration of 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 instability,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.
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.of the People’s Republic of China (“China”).
Currently, our only producing operationsassets are conducted throughin Venezuela. Since 1992, our 80 percent-owned Venezuelan subsidiary, Harvest Vinccler C.A.S.C.A. (“Harvest Vinccler”, formerly Benton Vinccler, C.A.), 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.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 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 18, 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
In September 2004, we announced
United States of America (“GAAP”) for the redemption on November 1, 2004 of all $85 millionyear ended December 31, 2006 do not reflect the net results of our 9.375 percent senior unsecured notes due Novemberproducing 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, 2007 (the “2007 Notes”).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 August2006, Harvest Vinccler resolved and September 2004, we purchased West Texas Intermediate (“WTI”) crude oil puts covering 10,000 barrelssubstantially paid all of oil per daythe tax claims made by the SENIAT, the Venezuelan income tax authority. Harvest Vinccler paid $73.8 million additional taxes and related interest for calendar year 2005 to protect our 2005 cash flow. These puts costthe periods of 2001 through first quarter 2006.
At December 31, 2006, Harvest Vinccler had three loans outstanding with two Venezuelan banks for a total of $14.9225 billion Venezuelan Bolivars (“Bolivars”) (approximately $104.7 million). These loans are collateralized by $88.9 million have an average strike pricedeposited in two U. S. banks. The loans were used to meet the SENIAT income tax assessments and related interest, refinance a portion of $42.20 per barrelone of the Bolivar loans and due to our pricing structure for our Venezuelan oil, have the economic effect of hedging approximately 20,800 barrels of oil per day. During 2004, we drilled ten new wells fund operating requirements.
SeeItem 1 – Business, Operations, Item 1A – Risk Factors,and
re-entered and completed an additional six wells in the South Monagas Unit. Our daily crude oil and natural gas sales on December 31, 2004, were 29,000 barrels of oil and 77 million cubic feet of gas. SeeItem 7 – Management’s Discussion and Analysis of Financial ConditionsCondition and Results of Operationsfor a complete description of these and other events during
2004.2006.
As of December 31,
2004, we had total estimated Proved Reserves in the South Monagas Unit, net of minority interest, of 84.4 million barrels of oil equivalent (“MMBoe”), and a standardized measure of discounted future net cash flow, before income taxes, for total Proved Reserves of $802 million. As of December 31, 2004,2006, we had total assets of $367.5$422.7 million. We had unrestricted cash in the amount of $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, 2005, we had total assets of $400.8 million. We had cash in the amount of $84.6$163.0 million, and no long-term debt. We haddebt, total revenues of $186.1$236.9 million and net cash provided by operating activities of $74.1$114.7 million. For the year ended December 31, 2003, we had cash in the amount of $138.7 million and $96.8 million in long-term debt. We had total revenues of $106.1 million and net cash provided by operating activities of $38.5 million.
2
Our business strategy is to identify, acquire,seek and develop and produce large discovered oil and gas fieldsknown resources in Venezuela and Russia. We have morecountries perceived as politically challenging. Our strategy is to diversify risk by adding projects in countries other than twelve years of experience in Venezuela and Russia, and have established organizations in both countries. We seek additional opportunities in these two countries and would consider investments in other countries that meet our criteria.Venezuela. In executing our business strategy, we will strive to sustain the current balance sheet strength through:
to:
| | • | maintaining | maintain financial prudence and rigorous investment criteria; |
| |
| | • | maximizing cash flows from existing operations in order to invest in new opportunities; | access capital markets; |
| |
| | • | using | create a diversified portfolio of assets; |
|
| • | | preserve our financial flexibility; |
|
| • | | use our experience, skills and cash on handrelationships to acquire new projects; and |
| |
| | • | keeping | 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, we seekour goal, post conversion, is to deliver maximum operatinginfluence the management and operations of Petrodelta while developing and producing the SMU 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
flow through the efficient management of our capital expenditure programs and cost structure. The year 2004 represented our first full year of natural gas production, which allowed us to diversify our revenues and cash flow. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures. We have significant financial flexibility and substantial cash flow supported by current oil prices and current production levels for both oil and gas. We believe this provides us with the ability to pursue growth opportunities while atin countries other than Venezuela. However, this strategy is limited by factors including access to additional capital, timing for conversion and restrictions on the same time maintaininguse of a strong balance sheet. However, we have recently experienced difficulties in Venezuela with gettingsignificant portion of our budgets approved and obtaining permits from the Ministry of Energy and Petroleum (“MEP”, formerly Ministry of Energy and Mines) and Ministry of Environment, as required, which are critical to our ability to fully execute our drilling program. A continuation of these difficulties or a curtailment of production in Venezuela could adversely affect our production and our ability to pursue growth opportunities.cash.
While we cannot predict the degree to which we will be successful, we continue to evaluate properties in both Venezuela and Russia to find opportunities which meet our focused acquisition criteria. We expect our cash generating capacity to be supported by our new gas production, lower operating expenses and our expected future Uracoa and Bombal drilling programs.2
Our
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. See
Item 1A – Risk Factors,Item 7 – Management’s Discussion and Analysis of Financial ConditionsCondition 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.
We also make available, free of charge on or through our Internet website
(http:(http://www.harvestnr.com)www.harvestnr.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, 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.
3
All of our operations are in Venezuela. Since 2005, Harvest Vinccler has been unable to execute its facilities and drilling program due to actions by the Venezuelan government, and daily production of oil and natural gas volumes have and will continue to decline. In 2006, we completed a ten-well workover program to mitigate the normal decline curve. Harvest Vinccler is currently operating the South Monagas Unit comprising the Uracoa, Tucupita and Bombal fields (the “SMU fields”) pending the completion of the conversion of the OSA to Petrodelta. We began the year with average oil deliveries of 22,000 barrels of oil per day (“Bopd”) and natural gas deliveries of 56 million cubic feet a day (“MMCFpd”). The fields currently produce approximately 17,000 Bopd and 37 MMCFpd.
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,
2004, 20032006, 2005 and
2002. All2004. The Venezuelan reserves are attributable to
an operating service agreementour OSA between Harvest Vinccler and
Petroleos de Venezuela S.A. (“PDVSA”)PDVSA under which all mineral rights are owned by the Government of Venezuela.
We own 80 percent of Harvest Vinccler. The reserve information presented below is net of a 20 percent deduction for the minority interest in Harvest Vinccler. Drilling and production activity and financial data are reflected without deduction for minority interest.
ReservesFor 2004 and 2005, the year-end reserves include production projected through
the endtermination of the
operating service agreementOSA in 2012.
TheIn April 2006, the Venezuelan
national civil work stoppage required Harvest 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 the operating service agreement pursuant to the force majeure provisions of the agreement.| | | | | | | | | | | | | |
| | | Harvest Vinccler | |
| | | Year Ended December 31, | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | (Dollars in 000’s)
|
RESERVE INFORMATION: | | | | | | | | | | | | |
| Proved Reserves (MBoe) | | | 84,418 | | | | 96,364 | | | | 102,534 | |
| Discounted future net cash flow attributable to proved reserves, before income taxes | | $ | 802,022 | | | $ | 545,308 | | | $ | 481,284 | |
| Standardized measure of discounted future net cash flows | | $ | 544,980 | | | $ | 366,770 | | | $ | 317,799 | |
DRILLING AND PRODUCTION ACTIVITY: | | | | | | | | | | | | |
| Gross wells drilled | | | 16 | | | | 3 | | | | 13 | |
| Average daily production (Boe) | | | 36,418 | | | | 20,130 | | | | 26,598 | |
FINANCIAL DATA: | | | | | | | | | | | | |
| Oil and natural gas revenues | | $ | 186,066 | | | $ | 106,095 | | | $ | 126,731 | |
| Expenses: | | | | | | | | | | | | |
| Operating expenses and taxes other than on income | | | 33,297 | | | | 31,445 | | | | 31,608 | |
| Depletion | | | 34,108 | | | | 19,599 | | | | 22,685 | |
| Income tax expense | | | 38,968 | | | | 12,158 | | | | 4,866 | |
| | | | | | | | | | |
| Total expenses | | | 106,373 | | | | 63,202 | | | | 59,159 | |
| | | | | | | | | | |
| Results of operations from oil and natural gas producing activities | | $ | 79,693 | | | $ | 42,893 | | | $ | 67,572 | |
| | | | | | | | | | |
We disposed of our Russian investments partly in 2002 and partly in 2003. LLC Geoilbent (“Geoilbent”) and Arctic Gas Company (“Arctic Gas”) were accounted for under the equity method and were included at their respective ownership interests in our consolidated financial statements for the periods in which we owned such investments. Our year-end financial information contains results from our Russian operations based on a twelve-month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2003 and 2002 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002, and from Arctic Gas, until it was sold on April 12, 2002.
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.
43
| | | | | | | | | | | | | | | | | | | | | |
| | | Geoilbent | | | Harvest Vinccler | |
| | | Year Ended September 30, | | | Year Ended | |
| | | 2003 | | 2002 | | | 12/31/06 | | 12/31/05 | | 12/31/04 | |
| | | (Dollars in 000’s) | | | (Dollars in 000’s) | |
RESERVE INFORMATION: | | |
| Proved Reserves (MBbls) | | | (a | ) | | 25,356 | | |
| Discounted future net cash flow attributable to proved reserves, before income taxes | | | (a | ) | | $ | 117,229 | | |
| Proved Reserves (MBoe) | | | — | | 36,105 | | 84,418 | |
| Standardized measure of discounted future net cash flows | | | (a | ) | | $ | 92,939 | | | $ | — | | $ | 329,438 | | $ | 544,980 | |
DRILLING AND PRODUCTION ACTIVITY: | | |
| Gross development wells drilled | | | (a | ) | | 6 | | |
| Net development wells drilled | | | (a | ) | | 2 | | |
| Average daily production (Bbls) | | 5,242 | | 6,438 | | |
| Gross wells drilled | | | — | | 1 | | 16 | |
| Average daily production (Boe) | | | 29,389 | | 35,732 | | 36,418 | |
FINANCIAL DATA: | | |
| Oil and natural gas revenues | | $ | 27,876 | | $ | 31,039 | | | $ | 59,506 | | $ | 236,941 | | $ | 186,066 | |
| Expenses: | | |
| Operating, selling and distribution expenses and taxes other than on income | | 16,088 | | 16,902 | | |
| Operating expenses and taxes other than on income | | | 9,451 | | 39,969 | | 33,297 | |
| Depletion | | 6,215 | | 9,237 | | | 9,904 | | 41,175 | | 34,108 | |
| Write-down of oil and gas properties | | 32,300 | | — | | |
| Income tax expense | | 2,073 | | 1,955 | | |
Income tax expense(a) | | | 20,076 | | 65,943 | | 38,968 | |
| | | | | | | | | | | | | |
| Total expenses | | 56,676 | | 28,094 | | | 39,431 | | 147,087 | | 106,373 | |
| | | | | | | | | | | | | |
| Results of operations from oil and natural gas producing activities | | $ | (28,800 | ) | | $ | 2,945 | | | $ | 20,075 | | $ | 89,854 | | $ | 79,693 | |
| | | | | | | | | | | | | |
(a) Geoilbent was sold on September 25, 2003. We owned, free
| | |
| (a) | | Excludes taxes of $50.3 million recorded in 2006 due to the settlement of the SENIAT tax assessments. |
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 any saleDecember 31, 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 transfer restrictions, until it was sold on April 12, 2002, 39natural 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 will 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 financial operating data for the period.MOU.
| | | | | |
| | | Arctic Gas Company | |
| | | Year Ended | |
| | | September 30, 2002 | |
| | | (Dollars in 000’s) | |
RESERVE INFORMATION: | | | | |
| Proved Reserves (MBoe) | | | (a | ) |
| Discounted future net cash flow attributable to proved reserves, before income taxes | | | (a | ) |
| Standardized measure of discounted future net cash flows | | | (a | ) |
DRILLING AND PRODUCTION ACTIVITY: | | | | |
| Gross wells reactivated | | | (a | ) |
| Average daily production (Bbls) | | | 189 | |
FINANCIAL DATA: | | | | |
| Oil and natural gas revenues | | $ | 3,554 | |
| Expenses: | | | | |
| Selling and distribution expenses | | | 1,429 | |
| Operating expenses and taxes other than on income | | | 1,673 | |
| Depletion | | | 139 | |
| Income tax expense | | | 19 | |
| | | | |
| Total expenses | | | 3,260 | |
| | | | |
| Results of operations from oil and natural gas producing activities | | $ | 294 | |
| | | | |
(a) Arctic Gas was sold on April 12, 2002.
5
South Monagas Unit Venezuela (Harvest Vinccler)
General
In July 1992, we and Venezolana de Inversiones y Construcciones Clerico, C.A., a Venezuelan construction and engineering company (“Vinccler”), signed a 20-year operating service agreement with Lagoven, S.A., an affiliate of PDVSA, to reactivate and further develop the
Uracoa, Tucupita and 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 Harvest Vinccler, our 80 percent-owned subsidiary. The remaining 20 percentday-to-day operations of the outstanding capital stock of Harvest Vinccler is owned by Vinccler. Through our majority ownership of stock in Harvest Vinccler, we makeSMU fields, the Venezuelan government has terminated all operational and corporate decisions related to Harvest Vinccler, subject to certain super-majority provisions of Harvest Vinccler’s charter documents related to:
| | Ÿ mergers; |
|
| | Ÿ consolidations; |
|
| | Ÿ sales of substantially all of its corporate assets; |
|
| | Ÿ change of business; and |
|
| | Ÿ similar major corporate events. |
Vinccler has an extensive operating history in Venezuela. It provided Harvest Vinccler with initial financial assistance and significant construction services. Vinccler provided assistance with construction projects, governmental relations and labor relations during 2004 and 2003.
services agreements effective April 2006.
Under the terms of the
operating service agreement,OSA, Harvest Vinccler is a contractor for
PDVSA.a 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 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 Harvest Vinccler to receive an operating fee for each barrel of crude oil delivered. It also provides Harvest 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 Harvest 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, Harvest 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. For 2004,thousand standard cubic feet (“Mcf”). The OSA stipulated that all payments for oil and natural gas sales averaged 85 million cubic feet (“MMcf”) per day. In addition, Harvest Vinccler agreedwere to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production (“Incremental Crude Oil”). Incremental Crude Oil is sold at a price of $7.00 per barrel with the quarterly volume of such sales based on quarterly natural gas sales multiplied by the ratio of 4.5 MMBbls to 198 Bcf.
At the end of each quarter, Harvest Vinccler prepares an invoice to PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted contract service fees per barrel. At the end of each quarter, Harvest Vinccler also prepares invoices for natural gas sales and Incremental Crude Oil. Payment is due under the invoices by the end of the second month after the end of the quarter. Invoice amounts and payments are denominatedbe paid in U.S. Dollars. Payments are wire transferredDespite 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 received 75 percent in U.S. Dollars and 25 percent in Bolivars.
Petrodelta
Upon receipt of the Venezuelan government approvals contemplated by the MOU, 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’s accountVinccler, and Harvest Vinccler Ltd., a Cayman Islands exempted company, owns a 0.1 percent general partnership interest in Harvest Vinccler. All of the equity interest in HNR Finance and Harvest Vinccler Ltd. is owned by Harvest Vinccler Dutch Holding B.V., a commercial bankDutch 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 United States.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 by CVP and Harvest Vinccler which will be set forth in Annex I to the Conversion Contract. Under the Conversion Contract, work programs and annual budgets adopted by Petrodelta must be consistent with the business 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 policies 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 board of directors to Petrodelta. Harvest Vinccler will fill its share of management positions with employees or secondees to Harvest Vinccler. The General Manager of Petrodelta will be appointed by the Board of Directors and will be in charge of the daily management of the business of Petrodelta and will 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 accordance 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 simple 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 capital stock of Petrodelta that would alter the percentage participation of HNR Finance or CVP; any liquidation or dissolution of Petrodelta; any merger, consolidation or business combination of Petrodelta; disposition of all or any substantial part of the assets of Petrodelta, except in the ordinary 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 policy regarding dividends and other distributions established by the Charter and By-laws; changes to the65
Harvest Vinccler has constructed a 25-mile oil pipeline from its oil processing facilities
business plan; changes to the contract for sale and purchase of hydrocarbons with PPSA; contracts with shareholders or affiliates that are not at Uracoamarket price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to PDVSA’s storage facility, the custody transfer point. The operating service agreement specifies that the oil stream may contain nolitigation involving more than one percent base sediment$1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and one percent water. Quality measurementsdesignation 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 conducted bothappointed 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 Harvest Vinccler’s facilitiesleast 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 and gas by Petrodelta to the 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 Annex 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
PDVSA’s storage facility. In 2003, we built$1.54 per thousand cubic feet. The reference price for crude oil and completed a 64-mile pipeline with a normal capacity of 70 MMcf ofthe price for natural gas per dayproduced from the Temblador, El Salto and a design capacityIsleño fields has not been set under the contract. PPSA will make payment to Petrodelta of 90 MMcfeach invoice by wire transfer, in United States Dollars (“U.S. Dollars”) in the case of payment for crude oil and natural gas per day, a gas gathering system, upgrades toliquids delivered, and in Bolivars in the UM-2 plant facilities and new gas treatment and compression facilities. Harvest Vinccler borrowed $15.5 million under a project loancase of payment for the gas pipeline and related facilities and the remainder of the project costs were funded from existing cash balances and internally generated cash flow. The operating service agreement contains requirements for the measurement and quality of the natural gas delivered, in immediately available funds to PDVSA.
In August 1999,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 been completed on April 1, 2006. The adjustment will take into account the value of oil and natural gas produced from April 1, 2006 and the costs incurred by Harvest Vinccler
sold its power generation facility located in
the Uracoa and Tucupita Fields. Concurrently with the sale, Harvest Vinccler entered into a long-term power purchase agreement with the purchaser of the facilityrelation to
provide for the electrical needs of the field throughout the remaining term of the operating service agreement. Harvest Vinccler has entered into long-term agreements for the leasing of compression and the operation and maintenance of the gas treatment and compression facilities.Risk Factors
Currently, the production from the such production.
South Monagas Unit represents all of our production. This production may be reduced by actions of the Venezuelan government. In addition, political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk. These risk factors and other risk factors are discussed in Item 7,Risk Factors.Location and Geology
The South Monagas Unit extends across the southeastern part of the state of Monagas and the southwestern part of the state of Delta Amacuro in eastern Venezuela. The South Monagas Unit is approximately 51 miles long and eight miles wide and consists of 157,843 acres, of which the fields comprise approximately one-half of the acreage. At December 31, 2004, Proved Reserves attributable to our Venezuelan operations were 105.5 MBoe (84.4 MBoe net to Harvest). This represented 100 percent of our Proved Reserves at year end. Harvest Vinccler has been primarily developing the Oficina sands in the Uracoa Field. The Uracoa Field contains 66 percent of the South Monagas Unit’s Proved Reserves.
Drilling and Development Activity
Harvest Vinccler drilled ten oil wells and re-entered an additional six wells in 2004 and had 124 wells on production in all fields at year end 2004 in the Uracoa Field.
Fields
Uracoa Field Harvest Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field.
There are currently
9082 oil and
natural gas producing wells in the field.
Harvest Vinccler processes the oil, water and natural gas in the Uracoa central processing unit and ships the processed oil via pipeline to the PDVSA custody transfer point. Harvest Vinccler treats and filters produced water, then reinjects it into the aquifer to assist the natural water drive. Harvest 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 Harvest Vinccler. This process design is commonly used in heavy oil production in the United States, but was not previously used extensively in Venezuela to process crude oil of similar gravity or quality. The current production facility has capacity to handle 60 thousand barrels (“MBbls”) of oil per day, 130 MBbls of water per day, and injection capacity of 46 MMcf of natural gas per day and storage of up to 75 MBbls of crude oil. All natural gas presently being solddelivered by Harvest Vinccler is produced from the Uracoa Field.
7
field.
There are currently
3019 oil producing wells and five 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 plant facilities.
Harvest Vinccler reinjects produced water from Tucupita into the aquifer to aid the natural water drive, and we utilize a portion of the associated natural gas to operate a power generation facility to supply our power needs.
Bombal Field
6
The East Bombal Fieldfield was drilled in 1992, and the wells were suspended until gas sales could take place.currently has one producing well. There are currently fourtwo 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 plant facilities. Development of the East Bombal field has been postponed pending completion of the conversion of the OSA to Petrodelta.
Infrastructure and Facilities
Harvest Vinccler began engineeringhas 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 studiescapacity 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
late 2004the Uracoa and Tucupita fields. Concurrently with
first gas sales expected in 2005. Gas from thisthe sale, Harvest Vinccler entered into a long-term power purchase agreements with the purchaser of the facilities to provide 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, all oil and natural gas produced is delivered to PDVSA for a fee. While we have substantial cash reserves, a prolonged loss of sales could have a material adverse effect on our financial condition.
Employees and Community Relations
agreement. Harvest Vinccler has entered into long-term agreements for the leasing of compression and the operation and maintenance of the gas treatment and compression facilities.
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 highly skilled staffportion of 219 local employeesthe 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 two expatriates. Harvest Vincclerdeveloped in the 1940s and the 1950s. Temblador has investedproduced 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 a Social Community Program that includes medical programs in ophthalmologic1936. A total of 31 appraisal wells have been drilled identifying nine productive structures and dental care,six productive formations. The field has produced less than 1 million Boe and is currently 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 call for the immediate resumption of the suspended development of 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.
7
Health, Safety and Environment
Harvest Vinccler’s health, safety and environmental policy is an integral part of its business.
Harvest Vinccler continually improves its policyhad previously identified and practices related to personnel safety, property protectionsubmitted in excess of 20 development wells for approval in the SMU fields. These wells will likely be the immediate focus of the restarted development program in Petrodelta. Concurrently, we envision the timely appraisal and environmental management. These improvementsdevelopment 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)
In September 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 8 – Russian Operations.
East Urengoy, Russia (Arctic Gas Company)
Arctic Gas Company was sold in April 2002. SeeNote 8 – 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
8
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. No further impairment of the property is currently required.
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,
2005.2007. While no assurance can be given, we believe we will continue to receive
licensecontract extensions so long as the
sovereignty issuesborder disputes persist.
Domestic Operations
We acquired a 100 percent interest in three California State offshore oil and gas leases (“the California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. In June 2004, we sold our California onshore property, which had a zero carrying value, for net proceeds of $0.6 million. We and other parties may be responsible to the State of California for any remediation costs associated with the onshore property and the related offshore oil and gas leases.
The following table summarizes our consolidated activities by area.
Total Assets represents all assets, including long-lived assets accounted for under the equity method:| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Other | | | Total | | | | | | | |
| (in thousands) | | Venezuela | | | Foreign | | | Foreign | | | United States | | | Total | |
| |
Year ended December 31, 2004 | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales | | $ | 186,066 | | | | — | | | $ | 186,066 | | | | — | | | $ | 186,066 | |
| Total Assets | | $ | 309,794 | | | $ | 385 | | | $ | 310,179 | | | $ | 57,307 | | | $ | 367,486 | |
| |
Year ended December 31, 2003 | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales | | $ | 106,095 | | | | — | | | $ | 106,095 | | | | — | | | $ | 106,095 | |
| Total Assets | | $ | 241,855 | | | $ | 237 | | | $ | 242,092 | | | $ | 132,256 | | | $ | 374,348 | |
| |
Year ended December 31, 2002 | | | | | | | | | | | | | | | | | | | | |
| Oil sales | | $ | 126,731 | | | | — | | | $ | 126,731 | | | | — | | | $ | 126,731 | |
| Total Assets | | $ | 209,733 | | | $ | 52,302 | | | $ | 262,035 | | | $ | 73,157 | | | $ | 335,192 | |
Reserves
Estimates of our Proved Reserves as of December 31, 2004 and 2003 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, 2004, which are all Venezuelan. The information includes reserve information net of a 20 percent deduction for the minority interest in Harvest Vinccler. All reserves are attributable to an operating service
98
agreement between Harvest 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 | | | 36,390 | | | | 26,124 | | | | 62,514 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| (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 | | | 64,718 | | | | 66,708 | | | | 131,426 | |
| | | | | | | | | | |
Estimates of commercially recoverable oil and natural gas reserves and of the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, such as:
| • | historical production from the subject properties; |
|
| • | comparison with other producing properties; |
|
| • | the assumed effects of regulation by governmental agencies; and |
|
| • | assumptions concerning future operating costs, municipal taxes, abandonment costs, development costs, and workover and remedial costs, all of which may vary considerably from actual results. |
All such estimates are to some degree speculative and various classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the commercially recoverable reserves of oil and natural gas attributable to any particular property or group of properties, the classification, cost and risk of recovering such reserves and estimates of the future net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times may vary substantially. The difficulty of making precise estimates is accentuated by the fact that 44 percent of our total Proved Reserves were undeveloped as of December 31, 2004. The cost to develop the Proved Undeveloped Reserves is expected to be $102.8 million over the next three years.
Reserve estimates are not constrained by the availability of the capital resources required to finance the estimated development and operating expenditures. In addition, actual future net cash flows will be affected by factors such as:
| • | actual production; |
|
| • | oil and natural gas sales; |
|
| • | supply and demand for oil and natural gas; |
|
| • | availability and capacity of gathering systems and pipelines; |
|
| • | changes in governmental regulations, policies or taxation; and |
|
| • | the impact of inflation on costs. |
The timing of actual future net oil and natural gas sales from Proved Reserves as well as the year-end price, and thus their actual present value, can be affected by the timing of the incurrence of expenditures in connection with development of oil and gas properties. The 10 percent discount factor required by the SEC to be used to calculate present value for reporting purposes is not necessarily the most appropriate discount factor based on interest rates in effect from time to time, risks associated with the oil and natural gas industry and the political risks associated with operations in Venezuela. Discounted present value, regardless of what discount rate is used, is materially affected by assumptions as to the amount and timing of future production, which assumptions may, and often do, prove to be inaccurate. For the period ending December 31, 2004, we reported $1,003 million ($802 million net to us) of discounted future net cash flows before income taxes from Proved Reserves based on the SEC’s required calculations.
10
Production, Prices and Lifting Cost Summary
In the following table we have set forth, by country, our net production, average sales prices and average operating expenses for the period ended March 31, 2006, and years ended December 31, 2004, 20032005 and 2002.2004. The presentation for Venezuela includes 100 percent of the production, without deduction for minority interest. Geoilbent (34 percent ownership) and Arctic Gas (39 percent ownership not subject to any sale or transfer restrictions at December 2001), which are accounted for under the equity method, have been included at their respective ownership interest in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, our results of operations for the years ended December 31, 2004, 2003 and 2002 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and from Arctic Gas until it was sold on April 12, 2002.
| | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2004 | | | 2003 | | | 2002 | |
Venezuela(a) | | | | | | | | | | | | |
| Crude Oil Production (Bbls) | | | 8,152,261 | | | | 7,347,399 | | | | 9,708,295 | |
| Natural Gas Production (Mcf) | | | 31,059,416 | | | | 2,660,241 | | | | — | |
| Average Crude Oil Sales Price ($per Bbl)(b) | | $ | 18.90 | | | $ | 14.88 | | | $ | 13.08 | |
| Average Natural Gas Sales Price ($per Mcf) | | $ | 1.03 | | | $ | 1.03 | | | | — | |
| Average Operating Expenses ($per Boe) | | $ | 2.50 | | | $ | 4.00 | | | $ | 3.26 | |
Russia | | | | | | | | | | | | |
Geoilbent(c)(d) | | | | | | | | | | | | |
| Net Crude Oil production (Bbls) | | | (d | ) | | | 1,913,187 | | | | 2,349,916 | |
| Average Crude Oil Sales price ($per Bbl) | | | (d | ) | | $ | 14.52 | | | $ | 13.21 | |
| Average Operating Expenses ($per Bbl) | | | (d | ) | | $ | 2.83 | | | $ | 2.09 | |
Arctic Gas(c)(e) | | | | | | | | | | | | |
| Net Crude Oil Production (Bbls) | | | (e | ) | | | (e | ) | | | (e | ) |
| Average Crude Oil Sales price ($per Bbl) | | | (e | ) | | | (e | ) | | | (e | ) |
| Average Operating Expenses ($per Bbl) | | | (e | ) | | | (e | ) | | | (e | ) |
| | | | | | | | | | | | | |
| | | 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. |
| |
(a)(b) | | Information represents 100 percent of production. |
| |
| (c) | (b) | Average crude oil sales price beforeafter hedging activity. |
|
| (c) | Information represents our ownership interest. |
|
| (d) | Geoilbent was sold on September 25, 2003. |
|
| (e) | Arctic Gas was sold on April 12, 2002. |
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;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 and
9
other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some
11
of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.
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. Dollar and restrict the ability to exchange
Venezuelan Bolivars for U.S. Dollars 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 Harvest Vinccler are allowed to receive payments for oil sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. We
have substantial cash reserves and do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet short-term loan obligations and operating requirements for the
next twelve months. Venezuela requires environmental and other permits for certain operations conducted in oil field development, such as site construction, drilling and seismic activities. As a contractor to PDVSA, Harvest Vinccler submits capital budgets to PDVSA for review, including capital expenditures to comply with Venezuelan environmental regulations.foreseeable future.
No capital expenditures to comply with environmental regulations were required in
20032004, 2005 or
2004. Harvest Vinccler also submits requests for permits for drilling, seismic and operating activities to PDVSA, which then obtains such permits from the MEP and Ministry of Environment, as required.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
$58.3 millionin 2006, 2005 and
$50.6 million in 2004,
2003 and 2002, respectively. Included in these numbers is
$33.5 million, $43.6$8.9 million and
$44.3$33.5 million for the development of
Proved Undeveloped Reservesproved undeveloped reserves in
2005 and 2004,
2003 and 2002, respectively.
We have drilled or participated through our equity affiliate in the drilling of wells as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | Year Ended December 31, |
| | | 2004 | | 2003 | | 2002 | | | 2006 | | 2005 | | 2004 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net | | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Wells Drilled: | | |
| Exploration: | | |
| Dry hole | | — | | — | | — | | — | | 1 | | 0.4 | | |
| Development: | | |
| Crude oil | | 16 | | 12.8 | | 3 | | 2.4 | | 18 | | 12.0 | | | — | | — | | 1 | | 0.8 | | 16 | | 12.8 | |
| | | | | | | | | | | | | | | |
| Total | | 16 | | 12.8 | | 3 | | 2.4 | | 19 | | 12.4 | | |
Average Depth of Wells (Feet) | | | — | | — | | — | | 4,349 | | — | | 5,443 | |
| | | | | | | | | | | | | | | |
Average Depth of Wells (Feet) | | 5,443 | | 6,095 | | | 7,341 | | |
Producing Wells(1): | | |
Producing Wells(1): | | |
| Crude Oil | | 124 | | 99.2 | | 111 | | 88.8 | | 258 | | 158.2 | | | 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 arewere 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 | |
| | | | | | | | | |
1210
Title to Undeveloped Acreage The following table summarizesWAB-21 petroleum contract lies within an area which is the developedsubject of a border dispute between China and undevelopedVietnam. Vietnam has executed an agreement on a portion of the same offshore acreage that we owned, leasedwith 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 heldhow this dispute will be resolved, and under operating service agreement or concession as of December 31, 2004:what terms the various countries and parties to the agreements may participate in the resolution.
| | | | | | | | | | | | | | | | | |
| | | Developed | | | Undeveloped | |
| | | Gross | | | Net | | | Gross | | | Net | |
| Venezuela | | | 11,726 | | | | 9,381 | | | | 146,117 | | | | 116,894 | |
| China | | | — | | | | — | | | | 7,470,080 | | | | 7,470,080 | |
| | | | | | | | | | | | | |
| Total | | | 11,726 | | | | 9,381 | | | | 7,616,197 | | | | 7,586,974 | |
| | | | | | | | | | | | | |
Competition
We encounter substantial 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, 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.
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.
At December 31, 2004, we2006, our Houston office had 1918 full-time employees. Harvest Vinccler had 219240 employees and our Moscow officeand London offices had 16 employees.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
Title
business plan; and the award of the Isleño, Temblador and El Salto fields to DevelopedPetrodelta 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
Undeveloped Acreage All Venezuelanobligations 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, areour 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 operating service agreement betweenunrelated 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 PDVSA, underCVP 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
mineral rights are owned by the Government of Venezuela. The WAB-21 petroleum contract lies within an area which is the subject of a territorial dispute between the People’s Republic of China and Vietnam. Vietnam has executed an agreement onor a portion of those projects. Failure by us to meet a capital requirement could be a default under the same offshore acreageConversion 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 third party. 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 territoriallegal 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 hasunder 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
many years,each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and
there has been limitednatural 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 development activitycommercially 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 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 April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month.
We moved into the new space in August 2004. In addition,Also during 2004, Harvest Vinccler leased
new office space in Maturin and Caracas, Venezuela for
approximately $13,200 and $4,000 per month, respectively.
We leased 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expired in December 2004. We subleased all of the office space in California for rents that approximated our lease costs. See also
“ItemItem 1 – Business” Businessfor a description of our oil and
natural gas properties and reserves.
13
Item 3. Legal Proceedings Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Harvest Vinccler,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.Assessments. In July 2004, Harvest Vinccler received three tax assessments from a tax inspector for the Uracoa municipality in which part of the
South Monagas Unit isSMU fields are located. A protest to the assessments was filed with the municipality, and in
SeptemberOctober 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 positions.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.
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PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
| | |
| 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 Stockcommon stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HNR”. As of December 31, 2004,2006, there were 36,779,40937,204,498 shares of common stock outstanding, with approximately 698589 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 | |
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 | |
| | | | | | | | | | | |
2004 | | First quarter | | | 14.25 | | | | 9.48 | |
| | | Second quarter | | | 17.00 | | | | 12.13 | |
| | | Third quarter | | | 16.60 | | | | 11.54 | |
| | | Fourth quarter | | | 18.25 | | | | 14.67 | |
| | | | | | | | | | | | | |
| 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
February 11, 2005,March 2, 2007, the last sales price for the common stock as reported by the NYSE was
$12.26$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, 2004.2006. 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 2002, 2001 and 20002002 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2002, 20012003 and 2000, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001 and 2000.2002.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | Year Ended December 31, | |
| | | 2004 | | 2003 | | 2002 | | 2001 | | 2000 | | | 2006(1) | | 2005 | | 2004 | | 2003 | | 2002 | |
| | | (in thousands, except per share data) | | | (in thousands, except per share data) | |
Statement of Operations: | | |
| Total revenues | | $ | 186,066 | | $ | 106,095 | | $ | 126,731 | | $ | 122,386 | | $ | 140,284 | | | $ | 59,506 | | $ | 236,941 | | $ | 186,066 | | $ | 106,095 | | $ | 126,731 | |
| Operating income | | 90,480 | | 33,627 | | 34,585 | | 28,201 | | 53,204 | | | 5,499 | | 119,525 | | 90,480 | | 33,627 | | 34,585 | |
| Net income | | 34,360 | | 27,303 | | 100,362 | | 43,237 | | 20,488 | | |
| Net income per common share: | | |
| Net income (loss) | | | | (58,562 | ) | | 50,839 | | 34,360 | | 27,303 | | 100,362 | |
| Net income (loss) per common share: | | |
| Basic | | $ | 0.95 | | $ | 0.77 | | $ | 2.90 | | $ | 1.27 | | $ | 0.67 | | | $ | (1.57 | ) | | $ | 1.38 | | $ | 0.95 | | $ | 0.77 | | $ | 2.90 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Diluted | | $ | 0.90 | | $ | 0.74 | | $ | 2.78 | | $ | 1.27 | | $ | 0.66 | | | $ | (1.57 | ) | | $ | 1.32 | | $ | 0.90 | | $ | 0.74 | | $ | 2.78 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | |
| Weighted average common shares outstanding | | |
| Basic | | 36,128 | | 35,332 | | 34,637 | | 33,937 | | 30,724 | | | 37,225 | | 36,949 | | 36,128 | | 35,332 | | 34,637 | |
| Diluted | | 38,122 | | 36,840 | | 36,130 | | 34,008 | | 30,890 | | | 37,225 | | 38,444 | | 38,122 | | 36,840 | | 36,130 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | Year Ended December 31, |
| | | 2004 | | 2003 | | 2002 | | 2001 | | 2000 | | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 |
| | | (in thousands) | | | (in thousands) |
Balance Sheet Data: | | |
| Total assets | | $ | 367,486 | | $ | 374,348 | | $ | 335,192 | | $ | 348,151 | | $ | 286,447 | | | $ | 422,711 | | $ | 400,798 | | $ | 367,486 | | $ | 374,348 | | $ | 335,192 | |
| Long-term debt, net of current maturities | | — | | 96,833 | | 104,700 | | 221,583 | | 213,000 | | | 66,977 | | — | | — | | 96,833 | | 104,700 | |
Stockholders’ equity(1)(2) | | 243,189 | | 199,713 | | 171,317 | | 67,623 | | 12,904 | | | 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
(1) No cash dividends were declared or paid during the periods presented.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsBusiness Strategy
We
intendhad 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
continuethe inability to
identify, acquirerecognize equity earnings for the producing operations in Venezuela since the second quarter of 2006 and
exploit known oilcharges of $73.8 million for additional taxes and
natural gas fieldsrelated interest in Venezuela for 2001 through 2006. We will not be able to report the results of our Venezuelan operations in our
current areasconsolidated 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
interest and possibly other areas while maintaining our financial strength and flexibility. To accomplishthe 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
we intend to:adjustment will not occur until the conversion is completed.
In 2006, the conversion to Petrodelta has progressed in a number of important areas:
| | • | Seek | In August, the MOU was amended to Deliver More Operating Cash Flow:In Venezuela, we seekprovide for the addition of the Isleño, Temblador and El Salto fields to deliver more operating cash flow throughPetrodelta as additional consideration for our conversion of the efficient managementOSA to Petrodelta. The addition of our capital expenditure programs and cost structure.these fields is subject to government approval. |
| |
| | • | Focus Our Efforts | In a special meeting of the stockholders in Areas of Low Geologic Risk:We intend to focusDecember 2006, our activities principally in areas of large known but undeveloped or under-developed oil and gas resources.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 Andand 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 Local Presence Through Joint Venture Partners and the Use of Local Personnel:We seek to establish a local presence in ourthe countries and areas of operationwe operate through joint venture partners to facilitate stronger relationships with local governmentgovernmental and labor.business relationships. In addition, usingwe use local personnel helpsto help us to take advantage of local knowledge and experience and to minimize costs. In pursuing new opportunities, we will seek to enter at an early stage and find local partners in an effort to reduce our risk in any one venture. |
| |
| | • | | Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital expenditureexpenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments so that we canto fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our |
16
maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure.
| • | Limit Exploration Activities:We do not engage in exploration except in connection with the expansion of an existing reservoir and in that case only where the risks are deemed to be manageable in the context of total cash exposure and probability of success. |
| |
| | • | | 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 significantsufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increasingincrease our liquidity. |
Risk Factors
In addition to the other information set forth elsewhere in thisForm 10-K, the following factors should be carefully considered when evaluating us.
Our only source of production may be reduced by actions of the Venezuelan Government. Currently, the production from the South Monagas Unit in Venezuela represents all of our production. Our revenue and cash flow will be adversely affected if we are not allowed to produce under our contract crude oil and natural gas at our projected levels. Recent events have increased the likelihood of this event occurring.
Under the operating service agreement Harvest Vinccler submits an annual budget to PDVSA for review and comment. Harvest Vinccler submitted to PDVSA its 2005 budget which provided for a $68 million drilling and facilities program. Under the terms of the operating service agreement this budget was deemed approved by PDVSA in November 2004. However, on December 17, 2004, Harvest Vinccler received letters from PDVSA seeking to reduce the 2005 drilling and facilities budget by over 60 percent and appearing to restrict average crude oil production for 2005 to about 20,400 barrels a day. At about the same time, Harvest Vinccler began to experience delays in the receipt of permits to drill new wells pursuant to its budget. In accordance with established procedures, Harvest Vinccler submitted requests to PDVSA to obtain permits from MEP for the drilling of eight wells. Only one of those requests was forwarded to the MEP. As a consequence of these delayed drilling permits, Harvest Vinccler began to run out of approved locations to continue its two-rig drilling program. On January 11, 2005, Harvest Vinccler formally notified one of its rig contractors that it would not be renewing its drilling contract and placed the rig on standby until January 29, 2005. Also, on January 11, 2005, Harvest Vinccler gave a thirty-day termination notice to the other rig company. On January 18, 2005, we announced that Harvest Vinccler was suspending its drilling program. In recent months, Harvest Vinccler has also experienced some operational interruptions in deliveries to PDVSA, although not of such a magnitude or duration as to affect production.
It has been reported that PDVSA has also sought to cut the budgets between 30 percent and 90 percent of the other 31 active operating service agreements in Venezuela. In addition, Rafael Ramirez, the President of PDVSA and Minister of MEP, has stated that PDVSA wants to renegotiate the terms of the operating service agreements as they are too costly, and that five or six of the operating service agreements have serious problems. It has been reported that one of these agreements is the South Monagas Unit operating service agreement held by Harvest Vinccler. Mr. Ramirez has also said that PDVSA will honor its contracts.
Collectively, these actions by the Venezuelan Government and PDVSA create a risk that our production will be reduced. Currently, Harvest Vinccler’s production has not been reduced, but if it is not allowed to conduct its drilling and facilities program, or if that program is restricted, then we will not meet our production forecasts and, over time, existing levels of production and available reserves will decline. While we believe such actions are not in accord with the operating service agreement, we and Harvest Vinccler are in discussions with Venezuelan officials and PDVSA to determine if these issues can be resolved through a mutually acceptable agreement. While we are hopeful of achieving a business solution, no assurance can be given that we will succeed or that the situation will not continue for an extended period of time. While we have substantial cash reserves, a prolonged curtailment of production or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition, results of operations and cash flows.
17
Political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk.Political and economic uncertainty is very high in Venezuela. From December 14, 2002 through February 6, 2003, PDVSA was unable to accept our oil due to the national civil work stoppage in Venezuela protesting the government of President Chavez. As a result, Harvest Vinccler’s 2002 oil deliveries were reduced by an estimated 0.6 million barrels and 2003 deliveries were reduced by an estimated 1.2 million barrels. In response to the national civil work stoppage, the Venezuelan government terminated several thousand PDVSA employees. As a result of the situation in PDVSA, its payment to Harvest Vinccler for crude oil delivered in the fourth quarter of 2002 was late by seven days. However, since then all other payments have been on time.
Following the national work stoppage, President Chavez prevailed in a recall referendum. In addition, PDVSA has been reorganized a number of times, most recently in January 2005. The current President of PDVSA is also the Minister of MEP. The political situation in Venezuela adds to the risk that we will be able to enforce the operating service agreement in Venezuela and could lead to further civil unrest and work stoppages that could affect our ability to produce crude oil and natural gas. In addition, the increasing integration of PDVSA into the governmental structure adds legal and economic uncertainty to our continued operations. These same risk factors could also affect our ability to acquire new projects in Venezuela and the timing of those acquisitions.
Acquiring new oil projects in Venezuela depends upon our ability to meet the requirements of the Organic Hydrocarbon Law.New oil projects in Venezuela are governed by the Organic Hydrocarbon Law, which requires that such projects be carried out through incorporated joint ventures with majority ownership by governmental entities. It is our understanding that the MEP is still defining the methodology for the application of this law. While we believe it is possible to comply with this 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.
Our strategy to focus on Russia carries deal execution, operating, financial, legal and political risks.While we believe our established presence in Russia and our experience and skills from prior operations position 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 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 relationships with Russian partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for Russian projects. 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. Our strategy in Russia depends on our ability to have operational and financial control. Recently, the Russian government has restricted certain “strategic” projects in Russia to majority-owned Russia companies. Such a policy, if widely applied, could adversely affect our ability to acquire projects in Russia consistent with our strategy.
Operations in areas outside the U.S. are subject to various risks inherent in foreign operations, and our strategy to primarily focus on Venezuela and Russia limits our country risk diversification.Our operations in areas outside the U.S. are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign policy, foreign trade, taxation 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.
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.
18
The total capital required for development of new fields may exceed our ability to finance. Our future capital requirements for new projects may exceed the cash available from existing free cash flow and cash on hand. Our ability to acquire financing is uncertain and may be affected by numerous factors beyond our control, including the risks associated with our sole operations in Venezuela. Because of the financial risk factors in the countries in which we operate, we may not be able to secure either the equity or debt financing necessary to meet any future cash needs for investment, which may limit our ability to fully develop new projects, cause delays with their development or require early divestment of all or a portion of those projects.
Our current and future revenue is subject to concentrated counter-party risk.Our current operations in Venezuela rely on production fee payments from PDVSA for all revenue receipts. We do not own the hydrocarbons and do not sell oil and gas in open markets. Future projects in Venezuela, Russia and other countries may involve similar production fee payments from a limited number of companies or governments.
Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela continues to be considered a highly inflationary economy. Results of operations in that country are measured in U.S. Dollars with all currency gains or losses recorded in the consolidated statement of operations. There are many factors which affect foreign exchange rates and resulting exchange gains and losses, many of which are beyond our influence. We 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. It is not possible to predict the extent to which we may be affected by future changes in exchange rates. Our Venezuelan receipts are denominated in U.S. Dollars, and most expenditures are in U.S. Dollars as well. For a discussion of currency controls in Venezuela, seeCapital Resources and Liquiditybelow. Successful acquisition of projects in Russia may also expose us to foreign currency risk in that country.
Oil price declines and volatility could adversely affect our revenue, cash flows and profitability. Prices for oil fluctuate widely. The average price we received for oil in Venezuela increased to $18.90 per Bbl for the year ended December 31, 2004, compared with $14.07 per Bbl for the year ended December 31, 2003. 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 our ability to service our 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 fluctuation include:
| • | relatively minor changes in the global supply and demand for oil; |
|
| • | 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 countries; and |
|
| • | overall economic conditions. |
Lower oil and natural gas prices or downward adjustments to our reserves may cause us to record ceiling limitation write-downs. We use the full cost method of accounting to report our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties. The estimated future net cash flows include the impact of effective hedging activity as applicable. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down”. This charge does not impact cash flow from operating activities, but does reduce stockholders’ equity. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. We did not incur ceiling test write-downs in 2004 in the consolidated financial statements of the wholly-owned and majority owned subsidiaries. Equity in Net Losses of Affiliated Companies
19
includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ended September 30, 2003.
Estimates of oil and natural gas reserves are uncertain and inherently imprecise. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. SeeOur only source of production may be reduced by actions of the Venezuelan Government.
The process of estimating oil and natural gas reserves is complex. Such process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves 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, ability to deliver under the terms of our operating service agreement, approval of capital budgets and permits from PDVSA and other factors, many of which are beyond our control. Actual production, revenue, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used. Such variances may be material.
At December 31, 2004, approximately 44 percent of our estimated Proved Reserves were undeveloped. Undeveloped reserves, by their nature, are less certain than developed reserves. The estimated future development cost increased by over $39 million to develop the Undeveloped Reserves. 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 is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in demand, our ability to produce or in governmental regulations, policies or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from estimated proved reserves and their present value. In addition, the 10 percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and our risks or the risks associated with the oil and natural gas industry in general will affect the accuracy of the 10 percent discount factor.
We may not be able to replace production with new reserves. In general, production rates and remaining reserves from oil and gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves in the South Monagas Unit in Venezuela will decline as they are produced unless we acquire additional properties in Venezuela, Russia or elsewhere with proved reserves or conduct successful exploration and development activities. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and natural gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.
Our operations are subject to numerous risks of oil and natural gas drilling and production activities.Oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is
20
often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
| • | 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.debt and equity markets. |
The prevailing price of oil also affects the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.
The oil and natural gas industry experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pump and pipe failures, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We cannot predict the continued availability of insurance at premium levels that justify its purchase.Competition within the industry may adversely affect our operations. We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies for the acquisition of desirable oil and gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.
Our oil and natural gas operations are subject to various governmental regulations that materially affect our operations. Our oil and natural gas operations are subject to various foreign governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated may include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve or limit supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.
Results of Operations
We include the results of operations of Harvest Vinccler in our consolidated financial statements and reflect the 20 percent ownership interest of Vinccler as a minority interest. We accounted for
Effective April 1, 2006, our
investments in Geoilbent and Arctic Gas usingoperations have been reflected under the equity
method. We included Geoilbent and Arctic Gas inmethod of accounting but our
consolidated financial statements based on a fiscal year ending September 30. Our results of operationsability to recognize equity earnings for the
years ended December 31, 2003 and 2002 reflectproducing operations in Venezuela are subject to completion of the
resultsconversion of
Geoilbent (until sold on September 25, 2003) and Arctic Gas (until sold on April 12, 2002) for the
twelve months ended September 30, 2002. You should readOSA 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
ofshould be read with the results of operations for each of the years in the three-year period ended December 31,
20042006 and the financial condition as of December 31,
20042006 and
20032005 in conjunction with our Consolidated Financial Statements and related Notes thereto.
21
We have presented selected expense items from our consolidated income statement as a percentage of revenue in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, |
| | | 2004 | | 2003 | | 2002 | | | 2006 | | 2005 | | 2004 |
| Operating Expenses | | | 18 | % | | | 29 | % | | | 27 | % | | | 16 | % | | | 17 | % | | | 18 | % |
| Depletion, Depreciation and Amortization | | 19 | | 20 | | 21 | | | 18 | | 19 | | 19 | |
| General and Administrative | | 12 | | 15 | | 13 | | | 44 | | 10 | | 12 | |
| Taxes Other Than on Income | | 3 | | 3 | | 3 | | | 7 | | 3 | | 3 | |
| Interest | | 4 | | 10 | | 13 | | |
| Interest Expense | | | 39 | | 1 | | 4 | |
24
Years ended December 31, 2004Ended 2006 and 2003 Net income for 2004 was $34.42005
We reported a net loss of $58.6 million, or
$0.90$1.57 diluted earnings per
diluted share,
for 2006 compared with
$27.3net income of $50.8 million, or
$0.74$1.32 diluted earnings per
diluted share, for
2003. Our results of operations for 2004 primarily reflected the results for Harvest-Vinccler in Venezuela, which accounted for all of our production2005.
Total expenses and oil and gas sales revenue. Oil revenue per barrel increased 34 percent (from $14.07 in 2003 to $18.90 in 2004) and oil sales quantities increased 11 percent (from 7.3 MBbls of oil in 2003 to 8.2 MBbls of oil in 2004) during 2004 compared with 2003. Natural gas sales quantities for 2004 from Venezuela were 31.1 Bcf. Revenue for 2004 includes 0.7 MBbls of oil at a $7.00 fixed price associated with the gas sales contract. Our revenues increased $80.0 million, or 75 percent, during 2004 compared with 2003. This was due to the addition of a full year of natural gas sales ($29.3 million), higher oil volumes ($7.7 million) and higher crude oil prices ($43.0 million). Our sales quantities for 2004 from Venezuela were 13.3 MBoe compared with 7.8 MBoe in 2003. The increase in sales quantities of 5.5 MBoe, or 71 percent, was due to a full year of natural gas production. Crude oil volumes for 2004 were also higher as 2003 was affected by the shut-in of the production in Venezuela from December 2002 to February 2003 due to the national work stoppage.
Our operating expenses increased $2.4 million, or 8 percent, for 2004 compared with 2003. This was primarily due to higher production volumes, higher workover and maintenance programs and increased insurance costs. Depletion, depreciation and amortization increased $14.8 million, or 70 percent, during 2004 compared with 2003 due to increased oil and gas production from Venezuela. Depletion expense per barrel of oil produced from Venezuela during 2004 was $2.56 compared with $2.52 during 2003. The increase was primarily due to increased future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during 2003.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
$6.1 million, or 39 percent, for 2004 compared with 2003. This was, in part, due to
severance payments for a number of employees paid in the second quarter of 2004, the write-off of project evaluationhigher business development costs
associated with projects in Russia, restricted stock bonuses recorded in the third quarter 2004, additional costs associated with Sarbanes-Oxley compliance and
an increase in liability under our deferred compensation plan for directors. An arbitration settlement of $1.5 million was recorded in 2003, and bad debt recoveries of $0.6 million and $0.4 million were recorded in 2004 and 2003, respectively,employee related
to an allowance for uncollectible accounts in prior years.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 $2.2due 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 65 percent, during 2004$1.32 diluted earnings per share, for 2005 compared with 2003. Thisnet 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
and gas revenues.
Investment income and other
The effective tax rate increased
$0.7 million, or 47to 46 percent
duringin 2005 from 41 percent in 2004
compared with 2003. This was due to higher interest rates earned on average cash balances. Interest expense decreased $2.7 million, or 26 percent, during 2004 compared with 2003 due to lower average outstanding debt balances for 2004 compared to 2003. In 2004, we redeemed all $85 million of our 2007 Notes, and we repaid all Bolivar denominated debt in March 2003. Net gain (loss) on exchange rates decreased $1.2 million, or 218 percent, for 2004 compared with 2003. This wasprimarily due to the significant devaluationpayment of $5.3 million related to a partial settlement of the Bolivar2001 through 2004 preliminary tax assessment.
Capital Resources and Bolivar currency controls imposedLiquidity
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
February 2003 which fixed the
exchange rate between the Bolivarconversion to Petrodelta, delays or inability of PDVSA to pay for past and
the U.S. Dollar and restricts the ability to exchange Venezuelan Bolivars for dollars and vice versa.22
We realized income before income taxes and minority interest of $81.3 million during 2004 compared with income of $71.8 million in 2003. The increase was primarily attributable to higherfuture crude oil and natural gas volumes and an increase in crude oil price in 2004 offset by the sale of our minority equity investment in Geoilbent in 2003. Income tax expense increased $23.6 million due to higher Venezuela pre-tax income. The effective tax rate increased from 13 to 41 percent for 2004 compared with 2003. The rate increase was due to foreign income taxes incurred on profitable foreign operations in 2004. The sale of our minority equity investment in Geoilbent in 2003 was offset by U.S. loss carryforwards. The income before minority interest decreased $14.2 million for 2004 compared with 2003. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by increased production of Harvest Vinccler.
Equity in net losses of affiliated companies decreased $28.9 million during 2004 compared to 2003. This was due to the elimination of Geoilbent equity losses on September 25, 2003, the date of its sale.
Years ended December 31, 2003 and 2002
Net income for 2003 was $27.3 million, or $0.74 per diluted share, compared with $100.4 million, or $2.78 per diluted share, for 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 an allowance for uncollectible accounts in prior years. Operating and general and administrative expenses were reduced by $3.8 million, or almost 8 percent, compared with 2002.
Our results of operations for 2003 primarily reflected the results for Harvest Vinccler in Venezuela, which accounted for all of our production and oil and gas sales revenue. Oil revenue per barrel increased 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 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. Revenue for 2003 includes 0.1 MMBbls of oil at the $7.00 fixed price associated with the gas sales contract.
Our revenues decreased $20.6 million, or 16 percent, during 2003 compared with 2002. This was primarily due to lower production offset by higher world crude oil prices. Our sales quantities for 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 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 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. The decrease was 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 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 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 an allowance for uncollectible accounts in prior years.
Taxes other than on income decreased $0.7 million, or 17 percent, during 2003 compared with 2002. This was primarily due to decreased Venezuelan municipal taxes which result from lower 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 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 2003 compared with 2002 due to lower average outstanding debt
23
balances for 2003 compared with 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 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 restrictsdeliveries, the ability to exchange Venezuelan Bolivars for dollarsimplement our business plan, changes in oil prices, fiscal and vice versa.
We realized income before income taxescontractual stability and minority interest of $71.8 million during 2003 compared with income of $169.8 million in 2002. The decrease was primarily attributable to the Arctic Gas Sale in 2002 offset by the saleexpropriation of our minorityassets. 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 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 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 interest decreased $47.4 million for 2003 compared with 2002. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by decreased production of Harvest Vinccler.
Equity in net losses of affiliated companies decreased $29.0 million during 2003 from income of $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.
Capital Resources and Liquidity
markets.
The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see
Item 1A — Risk Factors)Factors). We require capital principally to
service 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. |
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 and our ability to service our debt.expenditures.
26
On February 5, 2003,
Venezuela imposed currency controls and created the
GovernmentCommission for Administration of
Venezuela fixedForeign 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
restrictedrestrict the ability to exchange
Venezuelan Bolivars for U.S. Dollars and vice versa.
InitiallyThe Bolivar is not readily convertible into 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 Harvest Vinccler are allowed to receive payments for oil sales in U.S. Dollars and pay U.S. Dollar-denominated expenses from those payments. We
have substantial cash reserves and do not expect the Venezuelan currency conversion restriction to adversely affect our ability to meet
our short-term loan obligations and operating requirements for the
next twelve months.foreseeable future.
Our ability to replace production with new reservesacquire and develop growth opportunities outside of Venezuela 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 Harvest Vinccler
to make loan repayments, dividends andloans. We have no other
cash payments to us. However, there have been, and may again be, interruptions in oil and gas sales or there may be contractual obligations or legal impediments to receiving dividends or distributions from Harvest Vinccler, which could affect the ability of Harvest Vinccler to remit funds to us.Debt Reduction.In September 2004, we announced that the remaining 2007 Notes would be redeemed on November 1, 2004, and we irrevocably deposited with the Trustee for the 2007 Notes as trust funds $85.0 million plus accrued interest through November 1, 2004 and a prepayment call premium of $1.3 million to redeem the 2007 Notes on the redemption date. We were released from all obligations related to the 2007 Notes upon deposit of the trust funds with the Trustee. We recorded a loss on early extinguishment of debt of $2.9 million which includes the $1.3 million prepayment call premium, $0.7 million for interest related to the period October 1, 2004 to
24
obligations.
November 1, 2004 and $0.9 million write-off of unamortized debt financing costs. Our repayment of the 2007 Notes triggered an obligation under the terms of Harvest Vinccler’s loans from a Venezuelan commercial bank to renegotiate the terms of those loans or, if agreement on renegotiated terms cannot be reached within 30 days after November 1, 2004, the loans can be declared due and payable. Harvest Vinccler is in discussions with the Venezuelan bank on possible renegotiated terms. While we believe the loans will be renegotiated, it is possible that agreement will not be reached and Harvest Vinccler will be required to repay the remaining balance of $11.8 million. As of February 11, 2005, no agreement had been reached.
Working Capital.Our capital resources and liquidity are affected by the receiptconversion to Petrodelta and the ability of the quarterly payments from PDVSA at the end of the months of February, May, August and November pursuantPetrodelta to the terms of the operating service agreement for the South Monagas Unit. As a consequence of the timing of the PDVSA payment inflows, our cash balances can increase and decrease dramatically on a few dates during the year.
Harvest Vinccler’s oil and gas pipeline project loans of $11.8 million allow the lender to accelerate repayment if production ceases for a period greater than thirty days. A future disruption of production could trigger the debt acceleration provision.
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:
| | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | | | | | (in thousands) | | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| Net cash provided by operating activities | | $ | 74,140 | | | $ | 38,538 | | | $ | 42,627 | |
| Net cash provided by (used in) investing activities | | | (39,684 | ) | | | 38,191 | | | | 126,143 | |
| Net cash used in financing activities | | | (88,516 | ) | | | (2,570 | ) | | | (113,293 | ) |
| | | | | | | | | | |
| Net increase (decrease) in cash | | $ | (54,060 | ) | | $ | 74,159 | | | $ | 55,477 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | 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,
2004,2006, we had current assets of
$172.2$199.8 million and current liabilities of
$83.2$82.2 million, resulting in working capital of
$89.0$117.6 million and a current ratio of
2:2.4:1. This compares with a working capital of
$137.2$178.1 million and a current
rationratio of
4:3.9:1 at December 31,
2003.2005. The decrease in working capital of
$48.2$60.5 million was primarily due to the
prepaymentinability to reflect the net results of
our producing operations in Venezuela in our consolidated financial statements for the
2007 Notes offsetyear 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
higher crude oil prices and an increase in crude oil and natural gas sales in Venezuela.the SENIAT for 2001 through first quarter 2006.
Cash Flow from Operating Activities. During the
yearsyear ended December 31,
2004 and 2003,2006, 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
$74.1$114.7 million. The $139.1 million
and $38.5 million, respectively. The $35.6 million increasedecrease was
primarily due to
naturalthe collection of the first quarter accrued oil and gas sales
higher crude oil prices and the sale of our California onshore property,receivable which was offset by
Harvest Vinccler’s purchasethe charge in the second 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
two WTI crude oil puts and2006 under the
lossequity method of
$2.9 million on the early repayment of the 2007 Notes. As of September 30, 2004, we no longer have an obligationaccounting pending conversion to
make annual interest payments of approximately $8.0 million on the 2007 Notes.Petrodelta.
Cash Flow from Investing Activities.During the
yearsyear ended December 31,
2004 and 2003,2006, 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
$39.1$16.1 million and
$60.9 million, respectively.no restricted cash. The decrease in capital expenditures is due to the
completioncontinued suspension of our
gas project in 2003drilling program and the
timingfact that the conversion of
our 2004 Uracoa drilling program.the OSA to Petrodelta has not been finalized. The
year ended 2003 includedincrease in restricted cash is due to collateral for the
receipt of $69.5 millionnew borrowings to pay the tax assessments received from the
saleSENIAT and to fund operations. We continue to expend funds during the period prior to the conversion for workovers and maintenance of
our minority equity investment in Geoilbent. The timing and size of capital expenditures for the South Monagas Unit are largely atexisting wells. After the conversion to Petrodelta, our discretion, although PDVSA has recently attempted to limit Harvest Vinccler’s capital spending (seeRisk Factors). Our remaining capital commitments worldwidewill be determined by the business plan provided for in the Conversion Contract and the annual budget approved by the Petrodelta Board of Directors to implement the business plan. Outside of Venezuela, our capital commitments support our search for new acquisitions, are relatively minimalbusiness development efforts and are substantially at our discretion. We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements.
27
Cash Flow from Financing Activities.During the year ended
2004, we irrevocably deposited withDecember 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
TrusteeSENIAT income tax assessments and related interest and 120 billion Bolivars (approximately $55.8 million) for
our 2007 Notes as trust funds $85.0the 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
plus accrued interest through November 1, 2004of its U.S. Dollar debt (one payment of $0.3 million and
a prepayment call premiumfour payments of $1.3 million
to redeem the 2007 Noteseach on the
redemption date.variable rate loans) and 31 billion Bolivars (approximately $14.3 million) of its Bolivar debt. During the
same period,year ended December 31, 2005, Harvest Vinccler repaid $6.4 million of its U.S. Dollar denominated
debt. Duringdebt (four payments of $0.3 million each and four payments of $1.3 million each on the
year ended 2003, Harvest Vinccler25
variable rate loans).
repaid all of its Bolivar denominated debt ($2.2 million) and $1.2 million of its U.S. Dollar debt, which was an acceleration of the next two principal payments.
Contractual Obligations.Obligations
We have a lease obligation of approximately $17,000 per month for our Houston office space. This lease runs through April 2014. In addition, Harvest Vinccler leased newhas lease obligations for office space in Maturin and Caracas, Venezuela for approximately $13,200 and $4,000 per month, respectively. The Board of Directors Deferred Compensation Plan at December 31, 2004 represents 106,000 phantom stock shares with an aggregate liability of $1.8 million, or $17.27 per share, based on the December 31, 2004 stock price.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments (in thousands) Due by Period | | | Payments (in thousands) Due by Period | |
| | | Less than | | After 4 | | | Less than | | After 4 | |
| Contractual Obligation | | Total | | 1 Year | | 1-2 Years | | 3-4Years | | Years | | | Total | | 1 Year | | 1-2 Years | | 3-4 Years | | Years | |
| Long-Term Debt | | $ | 11,833 | | $ | 11,833 | | $ | — | | $ | — | | $ | — | | | $ | 104,651 | | $ | 37,674 | | $ | 38,140 | | $ | 28,837 | | $ | — | |
| Building Lease | | 3,117 | | 415 | | 421 | | 388 | | 1,893 | | | 2,775 | | 407 | | 400 | | 412 | | 1,556 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 14,950 | | $ | 12,248 | | $ | 421 | | $ | 388 | | $ | 1,893 | | | $ | 107,426 | | $ | 38,081 | | $ | 38,540 | | $ | 29,249 | | $ | 1,556 | |
| | | | | | | | | | | | | | | | | | | | | | | |
While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash on hand will provide sufficient capital resources and liquidity to fund our planned capital expenditures, investments in and advances to affiliates, and quarterly interest payment obligations for the next 12 months. Our expectation is based upon our current estimate of projected prices, production levels, and our assumptions that we will be allowed to carry out our capital program on acceptable terms, that there will be no disruptions or limitations on our production and that PDVSA will pay our invoices timely. Actual results could be materially affected if there is a significant change in our expectations or assumptions (seeRisk Factors). Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well as various economic and political conditions that have historically affected the oil and natural gas business. Additionally, prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond our control.
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 prices may affect our total planned development activities and capital expenditure program.
In August and September 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing two WTI crude oil puts. SeeNote 1 – Derivatives and Hedging. 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 Harvest 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 Harvest Vinccler.
During the year ended December 31,
2004,2005, our net foreign exchange
lossgain attributable to our international operations was
$0.6$2.8 million. The U.S. Dollar and Bolivar exchange rates were
fixed in February 2003 and adjusted in
February 2004.March 2005. No gains or losses were recognized from February
20032004 to February
2004.2005. 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. 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.
26
Critical Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of all wholly-owned and majority-owned subsidiaries. The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated.
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
accounted 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, Harvest 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 and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data, economic changes and 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. Changes in previous estimates of proved reserves result from new information obtained from production history, changes in economic factors and other relevant developments. 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.
27
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. Dollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in
U.SU.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. It is not possible to predict the extent to which we may be affected by future changes in exchange rates.
New Accounting Pronouncements
In
December 2004,February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard
123 (revised 2004) Share-Based Payment155 – Accounting for Certain Hybrid Financial Instruments (“SFAS
123R”155”),
an amendmentwhich eliminates the exemption from applying SFAS 133 to
Statement of Accounting Standards 123 and 95. SFAS 123R focuses primarily on accountinginterests in securitized financial assets so that similar instruments are accounted for
transactions in which an entity obtains employee services in share-based payment transactions. Public companies with a calendar year end will be required to adopt the provisionssimilarly regardless of the
standardform 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
periodsall financial instruments acquired or issued after the beginning
of the first fiscal year that begins after
JuneSeptember 15,
2005. We do2006. Early adoption is permitted. The adoption of SFAS 155 will not
expect SFAS 123R to have a material effect on our consolidated financial position, results of
operationoperations or cash flows.
In December 2004,March 2006, the FASB issued Statement of Financial Accounting Standard 153 Exchanges on Nonmonetary156 – Accounting for Servicing of Financial Assets (“SFAS 153”156”), an amendment of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productivewhich requires all separately recognized servicing assets and replaces it with a general exception for exchangesservicing liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of nonmonetaryservicing assets and servicing liabilities at fair value. Adoption is required as of the beginning of the first fiscal year that dobegins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 156 will not have commercial substance. We do not expect SFAS 153 to have a material effect on our consolidated financial position, results of operationoperations or cash flows.
In July 2006, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 48 (“FIN 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 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected
29
to 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 2004,2006, the SECFinancial Accounting Standards Board (“FASB”) issued Staff Accounting Bulletin 106SFAS 157 – Fair Value Measurement (“SAB 106”SFAS 157”) which provides guidance regarding the interaction ofestablishes 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 143 with the calculation of depletion and the full cost ceiling test of oil and gas properties under the full cost accounting rules of the SEC. The guidance provided in SAB 106 is157 will not expected to have a material effect on our consolidated financial position, results of operationoperations 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 overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year 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 January 2003,September 2006, the FASBSEC issued InterpretationStaff Accounting Bulletin No. 46108 (“FIN 46”SAB 108”) Consolidationregarding the process of Variable Interest Entities, whichquantifying financial statement misstatements. SAB 108 addresses the consolidationdiversity in practice in quantifying financial statement misstatements and the potential under current practice for the build up of variable interest entities (“VIEs”) by business enterprises that areimproper amounts on the primary beneficiaries. A VIE is an entity that doesbalance sheet. The guidance in SAB 108 did not have sufficient equity investment at risk to permit it to finance its activities without additional subordinateda material effect on our consolidated financial support, or whose equity investors lack the characteristicsposition, results of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (“FIN 46R”), to clarify some of the provisions of FIN 46,operations and to defer certain entities from adopting until the end of the first interim or annual reporting period ending after March 15, 2004. Application of FIN 46R is required in financial statements of public entities thatcash flows.
Off-Balance Sheet Arrangements
We do 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 types of VIEs is required in financial statements for periods ending after March 15, 2004. We believe we have no arrangements that would require the application of FIN 46R. We have noany off-balance sheet arrangements.
28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk We are exposed to market risk from adverse changes in oil and natural gas prices, interest rates and foreign exchange 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.
Harvest Vinccler hedged a portion of its 2003 oil production by purchasing a WTI crude oil “put” to protect its 2003 cash flow. In August and September 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing two WTI crude oil 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. We had no hedging transactions in place for our 2004
or 2006 production.
Total short-term debt at December 31,
20042006 of
$11.8$37.7 million consisted of Harvest 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. Dollar 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 (seeCapital Resources and Liquidityabove).
Item 8. Financial Statements and Supplementary Data The information required by this item is included herein on pages S-1 through S-33.S-28.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.
Item 9A. Controls and Procedures The
Securities and Exchange Commission, among other things,SEC 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.
29
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 consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation as of December 31,
2004,2006, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in
RulesRule 13a-15(e)
andor 15d-15(e) under the Exchange Act) 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
Securities and Exchange CommissionSEC’s rules and
forms.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 RulesRule 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 our internal control over financial reporting was effective as of December 31, 2004.2006. 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, 2004,2006, and issued an attestation report which is included herein.
Item 9B. Other Information
None.
None.
3031
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 20052007 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 20052007 Annual Meeting of Shareholders.Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
| | |
| 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 20052007 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 20052007 Annual Meeting of Shareholders.Stockholders.
Item 14. Principal Accounting Fees and Services Please refer to the information under the caption “Independent Registered Public Accounting Firm” in our Proxy Statement for the 20052007 Annual Meeting of Shareholders.Stockholders.
3132
PART IV
Item 15. Exhibits and Financial Statement Schedules and Reports on Form 8-K
| | | | | | | | |
(a) | | | 1. | | | Index to Financial Statements: | | Page |
| | | | | | | | |
|
| | | | | | Report of Independent Registered Public Accounting Firm | | S-1 |
| | | | | | | | |
| | | | | | Consolidated Balance Sheets at December 31, 2004 and 2003 | | S-2 |
|
| | | | | | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002 | | S-3 |
| | | | | | | | |
| | | | | | Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003 and 2002 | | S-4 |
| | | | | | | | |
| | | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 | | S-5 |
| | | | | | | | |
| | | | | | Notes to Consolidated Financial Statements | | S-7 |
|
| | | 2. | | | Consolidated Financial Statement Schedules and Other: | | |
|
| | | | | | Schedule II - Valuation and Qualifying Accounts | | |
| | | | | | | | |
| | | | | Page |
| (a)1. | | Index to Financial Statements and Notes for LLC Geoilbent, a significant equity investment |
| | | | Statements: | | | | |
| | | | | | | All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto. |
| | | | | | | | S-1 | |
| | | 3. | | | Exhibits: | | |
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 December 11, 2003.April 6, 2006. (Incorporated by reference to Exhibit 3.73.2 to our Form 10-K10-Q filed on March 10, 2004,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 September 16, 2003,April 15, 2005, between Harvest Natural Resources, Inc. and Wells Fargo Bank, Minnesota, N.A. (incorporated(Incorporated by reference to Exhibit 5 to Amendment No. 14.3 to our Registration StatementForm 10-Q filed on Form 8-A filed OctoberApril 29, 2003 (Registration2005, File No. 000-17534)1-10762.). |
|
| | | | | | | |
| | | 10.1 | | | 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. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-52436).) |
32
| | | | | | | |
| | | 10.2 | | | Note payable agreement dated March 8, 2001 between Harvest 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.) |
| | | | | | | |
| | 10.3† | | 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.) |
| | | | | | |
| | | 10.4 | | | 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
| | | | | | | |
| | | 10.5 | | | 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.) |
| | | | | | |
| | | 10.6 | | | 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.) |
| | | | | | |
| | | 10.7 | | | 2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).) |
| |
| | | | | | |
| | | 10.8 | 10.6 | | Addendum No. 2 to Operating service agreementService Agreement Monagas SUR dated 19th September, 2002. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
| | | | | | | |
| | | 10.9 | | | Bank Loan Agreement between Banco Mercantil, C.A. and Harvest Vinccler C.A. dated October 1, 2002. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
| | | | | | | |
| | | 10.10 | | | 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.) |
| | | | | | |
| | 10.11† | | 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.) |
| | | | | | |
| | 10.12† | | Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.11 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
| | | | | | |
| | 10.13† | | Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.12 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
| | | | | | |
| | 10.14† | | Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.13 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
| | | | | | |
| | | 10.15 | | | Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.) |
| | | | | | |
| | 10.16† | | Employment Agreement dated November 17, 2003 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.18 to our Form 10-Q filed on March 10, 2004, File No. 1-10762.) |
33
| | | | | | |
| | 10.17† | | Employment Agreement dated September 1, 2004 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10-1 to our Form 10-Q filed on November 5, 2004, File No. 1-10762.) |
| | | | | | |
| | 10.1810.7† | | Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).) |
| |
| | | | | | |
| | 10.1910.8† | | 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.) |
| |
| | 10.2010.9† | | Form of 2004 Long Term Stock Incentive Plan Stock Option AgreementAgreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
|
| | | | | | | |
| | 10.2110.10† | | Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock AgreementAgreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
|
| | | | | | | |
| | 10.2210.11† | | Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock AgreementAgreement. (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 October 27, 2005, File No. 1-10762.) | | |
| |
| 10.13† | | Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
|
| | 21.110.14† | | Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
|
| 10.15† | | Employment Agreement dated September 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 10.1 to our Form 10-Q filed on 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 | | Harvest 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.) |
|
| 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.) |
|
| 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 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 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 SENIAT assessments. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on October 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 | | Amendment 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 6, 2006, File No. 1-10762.) |
|
| 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. |
|
| 10.33 | | Form 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 | 23.2 | | 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 | | | Certification of the Chief Executive Officer 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 of the Chief Financial Officer accompanying the annual reportAnnual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002 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. |
(b) Reports on Form 8-K
On November 4, 2004, we filed a Report on Form 8-K with the Securities and Exchange Commission in which we furnished a press release announcing our results for the third quarter ended September 30, 2004 and furnishing the following financial statements: (i) Consolidated Balance Sheets for the Period Ended September 30, 2004 and December 31, 2003; (ii) Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2004 and 2003; and (iii) Consolidated Statement of Cash Flows for the Three and Nine Months Ended September 30, 2004 and 2003.
On December 14, 2004, we filed a Report on Form 8-K with the Securities and Exchange Commission in which we furnished a press release providing financial and operating guidance assumptions for 2005.
3436
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReport of Independent Registered Public Accounting FirmTo the Board of Directors and Stockholders of Harvest Natural Resources, Inc.:
We have completed an integrated auditaudits of Harvest Natural Resources, Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements2006, 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)15(a) (1) present fairly, in all material respects, the financial position of Harvest Natural Resources, Inc. and its subsidiaries at December 31,
20042006 and
2003,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,
20042006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule
listed 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. 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 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 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 compensation to the fair value based method effective January 1, 2003.Petrodelta.
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,
20042006 based on criteria established in
Internal 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,
2004,2006, based on criteria established in
Internal 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 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
February 22, 2005March 13, 2007
S-1
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | | | | | | | |
| | | December 31, | | | December 31, | �� |
| | | 2004 | | 2003 | | | 2006 | | 2005 | |
| | | (in thousands, except per | | | (in thousands, except per | |
| | | share data) | | | share data) | |
| ASSETS | | |
| Current Assets: | | |
| Cash and cash equivalents | | $ | 84,600 | | $ | 138,660 | | | $ | 148,079 | | $ | 163,019 | |
| Restricted cash | | 12 | | 12 | | | 15,888 | | — | |
| Accounts and notes receivable: | | |
| Accrued oil sales | | 58,937 | | 32,766 | | |
| Accrued oil and gas sales | | | — | | 60,900 | |
| Joint interest and other, net | | 12,780 | | 11,197 | | | 9,811 | | 10,750 | |
| Put options | | 14,209 | | — | | |
| Advances to provisional equity affiliate | | | 19,146 | | — | |
| Deferred income tax | | 251 | | — | | | 5,608 | | 3,052 | |
| Prepaid expenses and other | | 1,426 | | 805 | | | 1,246 | | 2,149 | |
| | | | | | | | | | | |
| Total Current Assets | | 172,215 | | 183,440 | | | 199,778 | | 239,870 | |
| Restricted Cash | | 16 | | 16 | | | 73,001 | | — | |
| Other Assets | | 2,072 | | 2,080 | | | 176 | | 1,600 | |
| Deferred Income Taxes | | 6,034 | | 4,749 | | |
| 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 2004 and 2003, respectively) | | 631,082 | | 593,622 | | |
| 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 | | 10,008 | | 8,948 | | | 1,375 | | 9,568 | |
| | | | | | | | | | | |
| | | 641,090 | | 602,570 | | | 4,275 | | 651,252 | |
| Accumulated depletion, depreciation, and amortization | | | (453,941 | ) | | | (418,507 | ) | | | (955 | ) | | | (491,924 | ) |
| | | | | | | | | | | |
| Net Property and Equipment | | 187,149 | | 184,063 | | | 3,320 | | 159,328 | |
| | | | | | | | | | | |
| | | $ | 367,486 | | $ | 374,348 | | | $ | 422,711 | | $ | 400,798 | |
| | | | | | | | | | | |
| | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | |
| Current Liabilities: | | |
| Accounts payable, trade and other | | $ | 8,428 | | $ | 4,163 | | | $ | 3,827 | | $ | 408 | |
| Accounts payable, related party | | 11,063 | | 10,557 | | | 9,637 | | 9,203 | |
| Accrued expenses | | 29,355 | | 15,069 | | | 12,975 | | 18,444 | |
| Accrued interest payable | | 71 | | 1,427 | | |
| Accrued interest | | | 6,850 | | 2,637 | |
| Deferred revenue | | | 11,217 | | 6,728 | |
| Income taxes payable | | 22,475 | | 8,647 | | | 34 | | 18,909 | |
| Current portion of long-term debt | | 11,833 | | 6,367 | | | 37,674 | | 5,467 | |
| | | | | | | | | | | |
| Total Current Liabilities | | 83,225 | | 46,230 | | | 82,214 | | 61,796 | |
| Long-Term Debt | | — | | 96,833 | | | 66,977 | | — | |
| Asset Retirement Liability | | 1,941 | | 1,459 | | | — | | 2,129 | |
| Commitments and Contingencies | | — | | — | | |
| Minority Interest | | 39,131 | | 30,113 | | | 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, 2004 and 2003; issued 37,544 shares and 36,405 shares at December 31, 2004 and 2003, respectively | | 375 | | 364 | | |
| 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 | | 185,183 | | 175,051 | | | 194,176 | | 188,242 | |
| Retained earnings | | 61,897 | | 27,537 | | | 54,174 | | 112,736 | |
| Accumulated other comprehensive loss | | | (487 | ) | | — | | |
| Treasury stock, at cost, 764 shares and 730 shares at December 31, 2004 and 2003, respectively | | | (3,779 | ) | | | (3,239 | ) | |
| Treasury stock, at cost, 770 shares at December 31, 2006 and 2005, respectively | | | | (3,844 | ) | | | (3,844 | ) |
| | | | | | | | | | | |
| Total Stockholders’ Equity | | 243,189 | | 199,713 | | | 244,886 | | 297,512 | |
| | | | | | | | | | | |
| | | $ | 367,486 | | $ | 374,348 | | | $ | 422,711 | | $ | 400,798 | |
| | | | | | | | | | | |
See accompanying notes to consolidated financial statements.
S-2
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2004 | | 2003 | | 2002 | | | 2006 | | 2005 | | 2004 | |
| | | (in thousands, except per share data) | | | (in thousands, except per share data) | |
Revenues | | |
| Oil sales | | $ | 154,075 | | $ | 103,920 | | $ | 127,015 | | | $ | 54,858 | | $ | 210,493 | | $ | 154,075 | |
| Gas sales | | 31,991 | | 2,740 | | — | | | 4,648 | | 26,448 | | 31,991 | |
| Ineffective hedge activity | | — | | | (565 | ) | | | (284 | ) | |
| | | | | | | | | | | | | | | |
| | | 186,066 | | 106,095 | | 126,731 | | | 59,506 | | 236,941 | | 186,066 | |
| | | | | | | | | | | | | | | |
| | | |
Expenses | | |
| Operating expenses | | 33,324 | | 30,893 | | 33,950 | | | 9,241 | | 39,723 | | 33,324 | |
| Depletion, depreciation and amortization | | 36,020 | | 21,188 | | 26,363 | | | 10,510 | | 43,968 | | 36,020 | |
| Write-downs of oil and gas properties and impairments | | — | | 165 | | 14,537 | | |
| General and administrative | | 21,857 | | 15,746 | | 16,504 | | | 26,421 | | 22,819 | | 21,857 | |
| Arbitration settlement | | — | | 1,477 | | — | | |
| Contribution to Science and Technology Fund | | | 3,887 | | — | | — | |
| Account receivable write-off on retroactive oil price adjustments | | | — | | 4,548 | | — | |
| Bad debt recovery | | | (598 | ) | | | (374 | ) | | | (3,276 | ) | | — | | — | | | (598 | ) |
| Gain on sale of long-lived asset | | | (578 | ) | | — | | — | | | — | | — | | | (578 | ) |
| Taxes other than on income | | 5,561 | | 3,373 | | 4,068 | | | 3,948 | | 6,358 | | 5,561 | |
| | | | | | | | | | | | | | | |
| | | 95,586 | | 72,468 | | 92,146 | | | 54,007 | | 117,416 | | 95,586 | |
| | | | | | | | | | | | | | | |
| | | |
| Income from Operations | | 90,480 | | 33,627 | | 34,585 | | | 5,499 | | 119,525 | | 90,480 | |
| Other Non-Operating Income (Expense) | | |
| Gain on disposition of investment | | — | | 46,619 | | 144,029 | | |
| Gain (loss) on early extinguishment of debt | | | (2,928 | ) | | — | | 874 | | |
| Loss on early extinguishment of debt | | | — | | — | | | (2,928 | ) |
| Investment earnings and other | | 2,085 | | 1,418 | | 2,080 | | | 9,406 | | 4,205 | | 2,085 | |
| Interest expense | | | (7,749 | ) | | | (10,405 | ) | | | (16,310 | ) | | | (23,156 | ) | | | (3,388 | ) | | | (7,749 | ) |
| Net gain (loss) on exchange rates | | | (622 | ) | | 529 | | 4,553 | | | | (121 | ) | | 2,752 | | | (622 | ) |
| | | | | | | | | | | | | | | |
| | | | (9,214 | ) | | 38,161 | | 135,226 | | | | (13,871 | ) | | 3,569 | | | (9,214 | ) |
| | | | | | | | | | | | | | | |
| | | |
| Income from Consolidated Companies Before Income Taxes and Minority Interest | | 81,266 | | 71,788 | | 169,811 | | |
| Income (Loss) from Consolidated Companies Before Income Taxes and Minority Interest | | | | (8,372 | ) | | 123,094 | | 81,266 | |
| Income Tax Expense | | 33,288 | | 9,657 | | 60,295 | | | 60,917 | | 57,025 | | 33,288 | |
| | | | | | | | | | | | | | | |
| Income Before Minority Interest | | 47,978 | | 62,131 | | 109,516 | | |
| Income (Loss) Before Minority Interest | | | | (69,289 | ) | | 66,069 | | 47,978 | |
| Minority Interest in Consolidated Subsidiary Companies | | 13,618 | | 5,968 | | 9,319 | | | | (10,727 | ) | | 15,230 | | 13,618 | |
| | | | | | | | | | | | | | | |
| Income from Consolidated Companies | | 34,360 | | 56,163 | | 100,197 | | |
| Equity in Net Income (Losses) of Affiliated Companies | | — | | | (28,860 | ) | | 165 | | |
| | | | | | | | | |
| Net Income | | $ | 34,360 | | $ | 27,303 | | $ | 100,362 | | |
| Net Income (Loss) | | | $ | (58,562 | ) | | $ | 50,839 | | $ | 34,360 | |
| | | | | | | | | | | | | | | |
| | | |
| Net Income Per Common Share: | | |
| Net Income (Loss) Per Common Share: | | |
| Basic | | $ | 0.95 | | $ | 0.77 | | $ | 2.90 | | | $ | (1.57 | ) | | $ | 1.38 | | $ | 0.95 | |
| | | | | | | | | | | | | | | |
| Diluted | | $ | 0.90 | | $ | 0.74 | | $ | 2.78 | | | $ | (1.57 | ) | | $ | 1.32 | | $ | 0.90 | |
| | | | | | | | | | | | | | | |
| | | |
| Other comprehensive loss: | | |
| Unrealized mark to market loss from cash flow hedging activities, net of tax | | | (487 | ) | | — | | — | | | — | | — | | | (487 | ) |
| | | | | | | | | | | | | | | |
| Comprehensive income | | $ | 33,873 | | $ | 27,303 | | $ | 100,362 | | |
| 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 | | Accumulated | | | | | | | Accumulated | | | | | |
| | | Common | | Additional | | Earnings | | Other | | | | | | | Common | | Additional | | Other | | | | | |
| | | Shares | | Common | | Paid-in | | (Accumulated | | Comprehensive | | Treasury | | | | | Shares | | Common | | Paid-in | | Retained | | Comprehensive | | Treasury | | | |
| | | Issued | | Stock | | Capital | | Deficit) | | Loss | | Stock | | Total | | | Issued | | Stock | | Capital | | Earnings | | Gain(Loss) | | Stock | | Total | |
| | | |
Balance at January 1, 2002 | | 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 | | |
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 | | | 53 | | — | | 600 | | — | | — | | — | | 600 | |
| Exercise of stock options | | 1,001 | | 10 | | 7,381 | | — | | — | | — | | 7,391 | | | 1,001 | | 10 | | 7,381 | | — | | — | | — | | 7,391 | |
| Employee stock-based compensation | | 85 | | 1 | | 2,151 | | — | | — | | — | | 2,152 | | | 85 | | 1 | | 2,151 | | — | | — | | — | | 2,152 | |
| Treasury stock (34 shares) | | — | | — | | — | | — | | — | | | (540 | ) | | | (540 | ) | | — | | — | | — | | — | | — | | | (540 | ) | | | (540 | ) |
| Accumulated other comprehensive loss | | — | | — | | — | | — | | | (487 | ) | | — | | | (487 | ) | | — | | — | | — | | — | | | (487 | ) | | — | | | (487 | ) |
| Net Income | | — | | — | | — | | 34,360 | | — | | — | | 34,360 | | | — | | — | | — | | 34,360 | | — | | — | | 34,360 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
Balance at December 31, 2004 | | 37,544 | | $ | 375 | | $ | 185,183 | | $ | 61,897 | | $ | (487 | ) | | $ | (3,779 | ) | | $ | 243,189 | | | 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, | | | Years Ended December 31, | |
| | | 2004 | | 2003 | | 2002 | | | 2006 | | 2005 | | 2004 | |
| | | (in thousands) | | | (in thousands) | |
| Cash Flows From Operating Activities: | | |
| Net income | | $ | 34,360 | | $ | 27,303 | | $ | 100,362 | | |
| 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 | | 36,020 | | 21,188 | | 26,363 | | | 10,510 | | 43,968 | | 36,020 | |
| Write-down of oil and gas properties and impairment | | — | | 165 | | 14,537 | | |
| Amortization of financing costs | | 228 | | 497 | | 1,745 | | | — | | — | | 228 | |
| Gain on disposition of assets and investments | | | (578 | ) | | | (46,619 | ) | | | (144,029 | ) | | — | | — | | | (578 | ) |
| Write off of unamortized financing costs | | 936 | | — | | — | | | — | | — | | 936 | |
| Equity in net earnings (losses) of affiliated companies | | — | | 28,860 | | | (165 | ) | |
| Account receivable write-off on retroactive oil price adjustments | | | — | | 4,548 | | — | |
| Allowance for employee notes and accounts receivable | | | (598 | ) | | | (169 | ) | | | (2,987 | ) | | — | | — | | | (598 | ) |
| Deferred compensation expense | | 1,521 | | 306 | | — | | | — | | | (745 | ) | | 1,521 | |
| Non-cash compensation related charges | | 2,152 | | 296 | | 1,458 | | | 5,056 | | 2,230 | | 2,152 | |
| Minority interest in consolidated subsidiary companies | | 13,618 | | 5,968 | | 9,319 | | | | (10,727 | ) | | 15,230 | | 13,618 | |
| Gain from early extinguishment of debt | | — | | — | | | (874 | ) | |
| Deferred income taxes | | | (1,285 | ) | | | (667 | ) | | 53,618 | | | | (2,556 | ) | | 2,982 | | | (1,285 | ) |
| Changes in operating assets and liabilities: | | |
| Accounts and notes receivable | | | (27,156 | ) | | | (7,935 | ) | | | (1,972 | ) | | 61,839 | | | (4,481 | ) | | | (27,156 | ) |
| Advances to provisional equity affiliate | | | | (19,146 | ) | | — | | — | |
| Prepaid expenses and other | | | (621 | ) | | 2,164 | | | (1,130 | ) | | 903 | | | (723 | ) | | | (621 | ) |
| Commodity hedging contract | | | (14,947 | ) | | | (430 | ) | | 430 | | | — | | 14,947 | | | (14,947 | ) |
| Accounts payable | | 4,265 | | 359 | | | (4,328 | ) | | 3,419 | | | (8,020 | ) | | 4,265 | |
| Accounts payable, related party | | 506 | | 4,386 | | | (604 | ) | | 434 | | | (1,860 | ) | | 506 | |
| Accrued interest payable | | | (1,356 | ) | | 22 | | | (2,489 | ) | |
| Accrued expenses | | 12,765 | | | (382 | ) | | | (9,686 | ) | | | (5,469 | ) | | | (10,165 | ) | | 12,765 | |
| Accrued interest | | | 4,213 | | 2,565 | | | (1,356 | ) |
| Deferred revenue | | | 4,489 | | 6,728 | | — | |
| Asset retirement liability | | 482 | | 1,459 | | — | | | 24 | | 188 | | 482 | |
| Income taxes payable | | 13,828 | | 1,767 | | 3,059 | | | | (18,875 | ) | | | (3,566 | ) | | 13,828 | |
| | | | | | | | | | | | | | | |
| Net Cash Provided by Operating Activities | | 74,140 | | 38,538 | | 42,627 | | |
| Net Cash Provided By (Used In) Operating Activities | | | | (24,448 | ) | | 114,665 | | 74,140 | |
| | | | | | | | | | | | | | | |
| Cash Flows from Investing Activities: | | |
| Proceeds from sale of investment | | — | | 69,500 | | 189,841 | | |
| Proceeds from sale of long-lived assets | | 578 | | — | | — | | | — | | — | | 578 | |
| Additions of property and equipment | | | (39,106 | ) | | | (60,925 | ) | | | (43,346 | ) | | | (1,657 | ) | | | (16,147 | ) | | | (39,106 | ) |
| Investment in and advances to affiliated companies | | — | | 2,328 | | 9,185 | | |
| Increase in restricted cash | | — | | — | | | (2,800 | ) | |
| Decrease in restricted cash | | — | | 1,800 | | 1,000 | | |
| Purchases of marketable securities | | — | | | (256,058 | ) | | | (353,478 | ) | |
| Maturities of marketable securities | | — | | 283,446 | | 326,090 | | |
| Investments in provisional equity affiliates | | | | (513 | ) | | — | | — | |
| (Increase) decrease in restricted cash | | | | (88,889 | ) | | 28 | | — | |
| Investment costs | | | (1,156 | ) | | | (1,900 | ) | | | (349 | ) | | 503 | | 472 | | | (1,156 | ) |
| | | | | | | | | | | | | | | |
| Net Cash Provided by (Used In) Investing Activities | | | (39,684 | ) | | 38,191 | | 126,143 | | |
| Net Cash Used In Investing Activities | | | | (90,556 | ) | | | (15,647 | ) | | | (39,684 | ) |
| | | | | | | | | | | | | | | |
| Cash Flows from Financing Activities: | | |
| Net proceeds from issuances of common stock | | 7,451 | | 1,201 | | 3,345 | | | 880 | | 767 | | 7,451 | |
| Purchase of treasury stock | | — | | | (404 | ) | | — | | |
| Proceeds from issuance of long-term debt | | — | | — | | 15,500 | | |
| Payments on long-term debt | | | (91,367 | ) | | | (3,367 | ) | | | (132,138 | ) | |
| Dividends paid to minority interest | | | (4,600 | ) | | — | | — | | |
| 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 Used In Financing Activities | | | (88,516 | ) | | | (2,570 | ) | | | (113,293 | ) | |
| Net Cash Provided By (Used In) Financing Activities | | | 100,064 | | | (20,599 | ) | | | (88,516 | ) |
| | | | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (54,060 | ) | | 74,159 | | 55,477 | | | | (14,940 | ) | | 78,419 | | | (54,060 | ) |
| Cash and Cash Equivalents at Beginning of Year | | 138,660 | | 64,501 | | 9,024 | | | 163,019 | | 84,600 | | 138,660 | |
| | | | | | | | | | | | | | | |
| Cash and Cash Equivalents at End of Year | | $ | 84,600 | | $ | 138,660 | | $ | 64,501 | | | $ | 148,079 | | $ | 163,019 | | $ | 84,600 | |
| | | | | | | | | | | | | | | |
| Supplemental Disclosures of Cash Flow Information: | | |
| Cash paid during the year for interest expense | | $ | 12,541 | | $ | 13,241 | | $ | 19,201 | | | $ | 23,171 | | $ | 795 | | $ | 12,541 | |
| | | | | | | | | | | | | | | |
| Cash paid during the year for income taxes | | $ | 11,705 | | $ | 4,254 | | $ | 3,935 | | | $ | 62,505 | | $ | 20,991 | | $ | 11,705 | |
| | | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements.
S-5
Supplemental Schedule of Noncash Investing and Financing Activities: During the year ended December 31,2006, we issued 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 2002 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 restricted stock valued at $1.2 million and we wrote-off $0.9 million of unamortized debt financing costs in connection with the redemption and discharge of the 9.375 percent senior unsecured notes due November 1,
2007. For the years ended December 31, 2003 and 2002, we recorded an allowance for doubtful accounts related to interest accrued on the remaining amount owed to us by our former chief executive officer, A. E. Benton. During the years ended December 31, 2004, 2003 and 2002, we reversed a portion of such allowance as a result of our collection of certain amounts owed to us including the portions of the note secured by our stock and other properties (seeNote 12 – Related Party Transactions)2007 (“2007 Notes”).
During Also during the year ended December 2004, the holders of our warrants elected to exercise 45,000 warrants on a cashless basis.basis by delivering Company shares to us. This resulted in the issuance of 34,054 shares which are held as treasury stock at cost.
See accompanying notes to consolidated financial statements.
S-6
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIES
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 (Harvestthrough our subsidiary Harvest Vinccler C.A. or “HarvestS.C.A. (“Harvest Vinccler” formerly Benton) 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
C.A.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. Dollar 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, Harvest Vinccler invoicesinvoiced 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. Dollar contract service fees per barrel. The operating service agreement providesrelated OSA with PDVSA provided for Harvest 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 Harvest Vinccler also invoicesinvoiced PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Harvest 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. 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.
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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,
2004,2006 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, which seriously affected many ofBecause the
country’s economic activities, in particular, the oil industry. As a result of the strike,conversion to Petrodelta has 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 and operating requirements for the next twelve months.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. 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 have 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 oil production. The changes in the fair value of these
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derivative instruments have been reported in other comprehensive income because the highly effective test was met, and have been reclassified to earnings in the period in which earnings were impacted by the variability of the cash flows of the hedged item.
Harvest Vinccler hedged a portion of its 2003 oil sales by purchasing a West Texas Intermediate (“WTI”) crude oil put option 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. Due to the pricing structure for our Venezuela oil, the put had the economic effect of hedging approximately 20,800 barrels of oil per day. The put cost was $2.50 per barrel, or $7.7 million, and had a strike price of $30.00 per barrel. The notional amount of the financial instrument was based on expected sales of crude oil production from existing and future development wells.
We had no hedging instruments in place for our 2004
or 2006 production. In August 2004, Harvest Vinccler hedged a portion of its oil sales for calendar year 2005 by purchasing a WTI crude oil put for 5,000 barrels of oil per day. The put cost was $4.24 per barrel, or $7.7 million, and
hashad a strike price of $40.00 per barrel. In September 2004, Harvest Vinccler hedged an additional portion of its calendar year 2005 oil sales by purchasing a second WTI crude oil put for 5,000 barrels of oil per day. The put cost was $3.95 per barrel, or $7.2 million, and
hashad 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
havehad the economic effect of hedging approximately
20,80021,500 barrels of oil per day for an average of
$18.29$17.72 per barrel. These puts
qualifyqualified under the highly effective test and the mark-to-market loss at December 31, 2004
iswas included in other comprehensive loss.
At December 31, 2004, Accumulated Other Comprehensive Loss consisted of $0.7 million ($0.5 million net of tax) of unrealized losses on our crude oil puts. Oil sales for the year ended 2004 included no losses in settlement of the puts.
Oil sales for the year ended 2003 included settlements of $1.7 million as well as the amortization of the put option cost of $7.7 million. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2004
are expected to bewere reclassified to earnings during 2005.
We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements.
All hedging instruments expired under their own terms on 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”)
. In January 2003, Harvest Vinccler recorded, under the full cost method of accounting for oil and gas properties, an increase in oil and gas properties and a corresponding liability in the amount of $4.3 million. This asset retirement obligation is associated with the plugging and abandonment ofS-8
certain wells in Venezuela. SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. NineNo wells were abandoned in the yearyears ended December 31, 2004 and 11 wells were abandoned in year ended December 31, 2003.2006 or 2005. Changes in asset retirement obligations during the years ended December 31, 20042006 and 20032005 were as follows:follows (in thousands):
| | | | | | | | | | |
| | | December 31, | | December, 31 | | | | | | | | | |
| | | 2004 | | 2003 | | | December 31, | | December 31, | |
| | | | 2006 | | 2005 | |
| Asset retirement obligations beginning of period | | $ | 1,459 | | $ | — | | | $ | 2,129 | | $ | 1,941 | |
| Liabilities recorded during the period | | 1,454 | | 4,237 | | | — | | 96 | |
| Liabilities settled during the period | | | (540 | ) | | | (733 | ) | | — | | — | |
| Revisions in estimated cash flows | | | (470 | ) | | | (2,125 | ) | | | (7 | ) | | | (17 | ) |
| Accretion expense | | 38 | | 80 | | | 31 | | 109 | |
| Reclassified to provisional equity affiliate | | | | (2,153 | ) | | — | |
| | | | | | | | | | | |
| Asset retirement obligations end of period | | $ | 1,941 | | $ | 1,459 | | | $ | — | | $ | 2,129 | |
| | | | | | | | | | | |
Accounts and Notes Receivable Allowance for doubtful accounts related to former employee notes at December 31,
20042006 and
20032005 was $2.8
million and $3.4 million, respectively. We received $0.5 million through the exercise of stock options and $0.1 million through the excess income provision of the settlement and release agreement. (seeNote 12 – Related Party Transactions).million.
Other assets consist of investigative costs associated with new projects. 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. 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 quarterly 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 and 2002, we recognized $0.2 million and $14.5 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,
20042006 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,
20042006 relate to the acquisition of Benton Offshore China Company and exploration related to its WAB-21 property. The ultimate timing of when the costs related to the acquisition of Benton Offshore China Company will be included in amortizable costs is uncertain.
All capitalized costs (including oilfield inventory and future abandonment costs under SFAS 143) and estimated future development 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,
2006, 2005 and 2004
2003was $9.9 million, $41.2 million and
2002 was $34.1 million
$19.6 million and $24.9 million ($
2.56, $2.523.74, $3.16 and $2.56 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.
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Depreciation of furniture and fixtures is computed using the straight-line method with depreciation rates based upon the estimated useful life of the property, generally 5 years. Leasehold improvements are depreciated over the life of the applicable lease. Depreciation expense was $1.9$0.6 million, $1.6$2.8 million and $1.4$1.9 million for the years ended December 31, 2006, 2005 and 2004, 2003 and 2002, respectively.
The major components of property and equipment at December 31 are as follows (in thousands):
| | | | | | | | | | |
| | | 2004 | | 2003 | | | | | | | | | |
| | | | 2006 | | 2005 | |
| Proved property costs | | $ | 621,679 | | $ | 582,456 | | | $ | — | | 630,634 | |
| Costs excluded from amortization | | 2,900 | | 2,900 | | | 2,900 | | 2,900 | |
| Oilfield inventories | | 6,503 | | 8,266 | | | — | | 8,150 | |
| Other administrative property | | 10,008 | | 8,948 | | | 1,375 | | 9,568 | |
| | | | | | | | | | | |
| | | 641,090 | | 602,570 | | | 4,275 | | 651,252 | |
| Accumulated depletion, impairment and depreciation | | | (453,941 | ) | | | (418,507 | ) | | | (955 | ) | | | (491,924 | ) |
| | | | | | | | | | | |
| | | $ | 187,149 | | $ | 184,063 | | | $ | 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
20042006 or
2003. Equity2005. 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,
20042006 and
2003,2005, we had several stock-based employee compensation plans, which are more fully described in
Note 5 – 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, 20042005 and 20032004 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.
| | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | 2003 | | 2002 | | | 2005 | | 2004 | |
| | | | (in thousands, except per share data) | |
| Net income, as reported | | $ | 34,360 | | $ | 27,303 | | $ | 100,362 | | | $ | 50,839 | | $ | 34,360 | |
| | | |
| Add: Stock-based employee compensation cost, net of tax | | 999 | | 296 | | 915 | | | 2,635 | | 999 | |
| | | |
| Less: Total stock-based employee compensation cost determined under fair value based method, net of tax | | | (1,382 | ) | | | (1,056 | ) | | | (2,905 | ) | | | (2,711 | ) | | | (1,382 | ) |
| | | | | | | | | | | | | |
| | | |
| Net income – proforma | | $ | 33,977 | | $ | 26,543 | | $ | 98,372 | | | $ | 50,763 | | $ | 33,977 | |
| | | | | | | | | | | | | |
| Net income per common share: | | |
| Basic – as reported | | $ | 0.95 | | $ | 0.77 | | $ | 2.90 | | | $ | 1.38 | | $ | 0.95 | |
| | | | | | | | | | | | | |
| Basic – proforma | | $ | 0.94 | | $ | 0.75 | | $ | 2.87 | | | $ | 1.37 | | $ | 0.94 | |
| | | | | | | | | | | | | |
| | | |
| Diluted – as reported | | $ | 0.90 | | $ | 0.74 | | $ | 2.78 | | | $ | 1.32 | | $ | 0.90 | |
| | | | | | | | | | | | | |
| Diluted – proforma | | $ | 0.89 | | $ | 0.72 | | $ | 2.75 | | | $ | 1.32 | | $ | 0.89 | |
| | | | | | | | | | | | | |
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Stock options of 0.1 million, 0.2 million and 1.1 million were exercised in the years ended December 31, 2006, 2005 and 2004, respectively, with cash proceeds of $0.9 million, $0.8 million and $8.0 million, respectively.
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.
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. Dollar is our functional and reporting currency. Amounts denominated in non-U.S. currencies are re-measured in U.S. 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. 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 book values of all financial instruments 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, was approximately $85.0 million. Our senior unsecured notes were repaid in the quarter ended September 30, 2004.
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-market losses from cash flow hedging activities as other comprehensive loss during the year ended December 31, 2004 and 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
December 2004,February 2006, the Financial Accounting Standards Board (“
FASB’FASB”) issued Statement of Financial Accounting Standard
123 (revised 2004) Share-Based Payment155 – Accounting for Certain Hybrid Financial Instruments (“SFAS
123R”155”),
an amendmentwhich eliminates the exemption from applying SFAS 133 to
Statement of Accounting Standards 123 and 95. SFAS 123R focuses primarily on accountinginterests in securitized financial assets so that similar instruments are accounted for
transactions in which an entity obtains employee services in share-based payment transactions. Public companies with a calendar year-end will be required to adopt the provisionssimilarly regardless of the
standardform 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
periodsall financial instruments acquired or issued after the beginning
of the first fiscal year that begins after
JuneSeptember 15,
2005. We do not expect SFAS 123R to have a material effect on our consolidated financial position, results of operation or cash flows.S-11
In December 2004, the FASB issued Statement of Financial Accounting Standard 153 Exchanges of Nonmonetary Assets (“SFAS 153”), an amendment of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. We do not expect SFAS 153 to have a material effect on our consolidated financial position, results of operation or cash flows.
In September 2004, the SEC issued Staff Accounting Bulletin 106 (“SAB 106”) which provides guidance regarding the interaction2006. Early adoption is permitted. The adoption of SFAS 143 with the calculation of depletion and the full cost ceiling test of oil and gas properties under the full cost accounting rules of the SEC. The guidance provided in SAB 106 is155 will not expected to have a material effect on our consolidated financial 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
no off-balance sheet arrangements.a material 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
20022004 and
20032005 have been reclassified to conform to the
20042006 financial statement presentation.
Note 2 -— Long-Term Debt and Liquidity Long-term debt consists of the following (in thousands):
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2004 | | | 2003 | |
| Senior unsecured notes with interest at 9.375% See description below | | $ | — | | | $ | 85,000 | |
| Note payable with interest at 6.1% See description below | | | 1,500 | | | | 2,700 | |
| Note payable with interest at 7.1% | | | 10,333 | | | | 15,500 | |
| | | | | | | |
| | | | 11,833 | | | | 103,200 | |
| Less current portion | | | 11,833 | | | | 6,367 | |
| | | | | | | |
| | | $ | — | | | $ | 96,833 | |
| | | | | | | |
| | | | | | | | | |
| | | 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 November 1997, we issued $115.0
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 9.375 percent senior unsecured notes due November 1, 2007 (“2007 Notes”),a U.S. bank to cover the line of which we repurchased $30.0 million. In September 2004, we announced that the remaining 2007 Notes would be redeemedcredit and accrued interest. The line of credit was used to meet short term Bolivar denominated obligations. The line of credit was repaid on November 1, 2004,24, 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 360 days after the funding date in the amount of 21 billion Bolivars (approximately $9.8 million), and we irrevocably deposited with21 billion Bolivars (approximately $9.8 million) every 180 days thereafter. A payment in the Trusteeamount of 20 billion Bolivars (approximately $9.3 million) was made on December 18, 2006. The interest rate for the 2007 Notes as trust funds $85.0first 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 collateralized by a $40.0 million plus accrued interest through November 1, 2004deposit in a U.S. bank. The loan was used to meet the SENIAT income tax assessments and a prepayment call premiumrelated interest.
S-12S-13
of $1.3 million to redeem the 2007 Notes on the redemption date. We were released from all obligations related to the 2007 Notes upon deposit of the trust funds
On October 3, 2006, Harvest Vinccler entered into a term loan with the Trustee. We recorded a loss on early extinguishment of debt of $2.9 million which includes the $1.3 million prepayment call premium, $0.7 million for interest related to the period October 1, 2004 to November 1, 2004 and $0.9 million write-off of unamortized debt financing costs. Our repayment of the 2007 Notes triggered an obligation under the terms of Harvest Vinccler’s loans from a Venezuelan commercial bank 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 renegotiatemeet the terms of those loans or, if agreement on renegotiated terms cannot be reached within 30SENIAT 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 is due 180 days after
November 1, 2004, the
loans can be declared due and payable. Harvest Vinccler is in discussions with the Venezuelan bank on possible renegotiated terms. The entire amount has been reclassified from long term to currentfunding date in the
interim. While we believe the loans will be renegotiated, it is possible that agreement will not be reached and Harvest Vinccler will be required to repay the remaining balance of $11.8 million. As of February 11, 2005, no agreement had been reached. In March 2001, Harvest 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, 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 limitations on mergers, and sale of assets. We have guaranteed the repayment of the remaining loan.
In October 2002, Harvest 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.20 billion Bolivars (approximately $9.3 million) every 180 days thereafter. The interest rate for thisthe first 180 days is fixed at 10.0 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 90-day LIBOR plus 6 percentage points.collateralized by a $40.4 million deposit in a U.S. bank. The term is four years withloan will be used to meet the SENIAT income tax assessments and related interest, refinance a quarterly amortizationportion of $1.3 million beginning with the first quarter 2004Bolivar loan and to coincide with the first payment from our gas sales.
We have classified all of our outstanding debt as current at December 31, 2004.
fund operating requirements.
Note 3 -— Commitments and Contingencies We have employment contracts with six 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,
2006 for five of the executives and on May 7, 2007 for the sixth executive.2008.
In April 2004, we signed a ten-year lease for office space in Houston, Texas, for approximately $17,000 per month.
We moved into the new space in August 2004. In addition,Also during 2004, Harvest Vinccler leased
new office space in Maturin and Caracas, Venezuela for $13,200 and $4,000 per month, respectively.
We leased 17,500 square feet of space in a California building that we no longer occupy under a lease agreement that expired in December 2004, all of which was subleased for rents that approximated our lease costs. Excel Enterprises L.L.C. vs. Benton Oil & Gas Company, now known as Harvest Natural Resources, Inc., Chemex, Inc., Harvest Vinccler,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.
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 South Monagas Unit isSMU fields are located. A protest to the assessments was filed with the municipality, and in SeptemberOctober 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 anya 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.
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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 will have a material adverse impact on our financial condition, results of operations and cash flows.
Taxes Other Than on Income Harvest Vinccler payspaid municipal taxes 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):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | 2003 | | 2002 | | | 2006 | | 2005 | | 2004 | |
| Venezuelan municipal taxes | | $ | 4,485 | | $ | 2,741 | | $ | 3,805 | | | $ | 3,191 | | $ | 5,788 | | $ | 4,485 | |
| Franchise taxes | | 464 | | 341 | | 139 | | | 175 | | | (70 | ) | | 464 | |
| Payroll and other taxes | | 612 | | 291 | | 124 | | | 582 | | 640 | | 612 | |
| | | | | | | | | | | | | | | |
| | | $ | 5,561 | | $ | 3,373 | | $ | 4,068 | | | $ | 3,948 | | $ | 6,358 | | $ | 5,561 | |
| | | | | | | | | | | | | | | |
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,
20042006 and
20032005 are as follows (in thousands):
| | | | | | | | | |
| | | 2004 | | | 2003 | |
| Deferred tax assets – non-current: | | | | | | | | |
| Operating loss carryforwards | | $ | 14,748 | | | $ | 20,442 | |
| Difference in basis of property | | | 28,753 | | | | 29,602 | |
| Other | | | 3,025 | | | | 3,070 | |
| Valuation allowance | | | (40,492 | ) | | | (48,365 | ) |
| | | | | | | |
| Net deferred tax asset – non-current | | $ | 6,034 | | | $ | 4,749 | |
| | | | | | | |
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| | | | | | | | | |
| | | 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
decreasedincreased by
$7.9$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):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | 2003 | | 2002 | | | 2006 | | 2005 | | 2004 | |
| Income (loss) before income taxes | | |
| United States | | $ | (16,593 | ) | | $ | 34,236 | | $ | 92,394 | | | $ | (15,688 | ) | | $ | 8,178 | | $ | (16,593 | ) |
| Foreign | | 97,859 | | 37,552 | | 77,417 | | | 7,316 | | 114,916 | | 97,859 | |
| | | | | | | | | | | | | | | |
| Total | | $ | 81,266 | | $ | 71,788 | | $ | 169,811 | | | $ | (8,372 | ) | | $ | 123,094 | | $ | 81,266 | |
| | | | | | | | | | | | | | | |
The provision (benefit) for income taxes consisted of the following at December 31, (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | 2003 | | 2002 | | | 2006 | | 2005 | | 2004 | |
| Current: | | |
| United States | | $ | (8 | ) | | $ | 1,187 | | $ | 351 | | | $ | — | | $ | 739 | | $ | (8 | ) |
| Foreign | | 34,581 | | 9,137 | | 6,326 | | | 63,473 | | 53,304 | | 34,581 | |
| | | | | | | | | | | | | | | |
| | | $ | 34,573 | | $ | 10,324 | | $ | 6,677 | | | 63,473 | | 54,043 | | 34,573 | |
| | | | | | | | | |
| | | |
| Deferred: | | |
| United States | | $ | — | | $ | — | | $ | 53,413 | | |
| Foreign | | | (1,285 | ) | | | (667 | ) | | 205 | | | | (2,556 | ) | | 2,982 | | | (1,285 | ) |
| | | | | | | | | | | | | | | |
| | | | (1,285 | ) | | | (667 | ) | | 53,618 | | | $ | 60,917 | | $ | 57,025 | | $ | 33,288 | |
| | | | | | | | | | | | | | | |
| | | $ | 33,288 | | $ | 9,657 | | $ | 60,295 | | |
| | | | | | | | | |
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A comparison of the income tax expense (benefit) at the federal statutory rate to our provision for income taxes is as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | 2003 | | 2002 | | | 2006 | | 2005 | | 2004 | |
| Computed tax expense at the statutory rate | | $ | 28,443 | | $ | 15,025 | | $ | 59,348 | | | $ | (2,930 | ) | | $ | 43,083 | | $ | 28,443 | |
| State income taxes | | 25 | | 1,188 | | 353 | | | — | | — | | 25 | |
| Effect of foreign source income and rate differentials on foreign income | | | (2,169 | ) | | | (15,849 | ) | | | (19,373 | ) | | 8,563 | | 16,065 | | | (2,169 | ) |
| Change in valuation allowance | | 7,020 | | 9,219 | | 19,446 | | | 5,446 | | 13,129 | | 7,020 | |
| All other | | | (31 | ) | | 74 | | 80 | | |
| | | | | | | | | |
| Sub-total income tax expense | | 33,288 | | 9,657 | | 59,854 | | |
| Effects of recording equity income of certain affiliated Companies on an after-tax basis | | — | | — | | 441 | | |
| Alternative minimum tax | | | — | | 739 | | — | |
| Venezuela tax settlement | | | 49,793 | | — | | — | |
| Net operating loss utilization | | | — | | | (15,567 | ) | | — | |
| Other | | | 45 | | | (424 | ) | | | (31 | ) |
| | | | | | | | | | | | | | | |
| Total income tax expense | | $ | 33,288 | | $ | 9,657 | | $ | 60,295 | | | $ | 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.jurisdictions.
At December 31, 2004,2006, we had, for federal income tax purposes, operating loss carryforwards of approximately $42.1$21.3 million, expiring in the years 20142021 through 2025.2026.
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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 5 — 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
companyCompany 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-Qualified Stock Options to eligible participants including employees of
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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
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changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.
Since 1989 we have adopted several other stock option plans under which options to purchase shares of our common stock have been granted to employees, officers, directors, independent contractors and consultants. Options granted under these plans have been at prices equal to the fair market value of the stock on the grant dates. Options granted under the plans are generally exercisable in varying cumulative periodic installments after one year and cannot be exercised more than ten years after the grant dates. Following the adoption of the 2001 Long Term Stock Incentive Plan, no options may be granted under any of these plans.
A summary of the status of our stock option plans as of December 31, 2004, 20032006, 2005 and 20022004 and changes during the years ending on those dates is presented below (shares in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | 2003 | | 2002 | | | 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: | | $ | 7.52 | | 4,523 | | $ | 7.42 | | 5,223 | | $ | 6.36 | | 6,865 | | | $ | 8.61 | | 4,070 | | $ | 8.18 | | 3,793 | | $ | 7.52 | | 4,523 | |
| Options granted | | 13.36 | | 378 | | 6.26 | | 246 | | 4.84 | | 165 | | | 10.62 | | 558 | | 11.51 | | 922 | | 13.36 | | 378 | |
| Options exercised | | | (7.41 | ) | | | (955 | ) | | 2.32 | | | (494 | ) | | 2.21 | | | (1,515 | ) | | | (5.69 | ) | | | (65 | ) | | | (3.45 | ) | | | (241 | ) | | | (7.41 | ) | | | (955 | ) |
| Options cancelled | | | (6.31 | ) | | | (153 | ) | | 11.37 | | | (452 | ) | | 8.03 | | | (292 | ) | | | (19.96 | ) | | | (440 | ) | | | (14.24 | ) | | | (404 | ) | | | (6.31 | ) | | | (153 | ) |
| | | | | | | | | | | | | | | |
| Outstanding at end of the year | | 8.18 | | 3,793 | | 7.52 | | 4,523 | | 7.42 | | 5,223 | | | 7.70 | | 4,123 | | 8.61 | | 4,070 | | 8.18 | | 3,793 | |
| | | | | | | | | | | | | | | |
| Exercisable at end of the year | | 7.71 | | 3,236 | | 8.18 | | 3,857 | | 8.49 | | 4,360 | | | 5.91 | | 2,719 | | 7.40 | | 2,886 | | 7.71 | | 3,236 | |
| | | | | | | | | | | | | | | |
Significant option groups outstanding at December 31, 20042006 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, 2004 | | | Contractual Life | | | Exercise Price | | | December 31, 2004 | | | Exercise Price | |
| $1.55 - $2.75 | | | 1,701,149 | | | | 4.93 | | | $ | 1.96 | | | | 1,701,149 | | | $ | 1.96 | |
| $4.80 - $7.10 | | | 410,834 | | | | 7.28 | | | | 5.74 | | | | 226,832 | | | | 5.57 | |
| $8.72 - $10.88 | | | 153,900 | | | | 0.73 | | | | 8.86 | | | | 153,900 | | | | 8.86 | |
| $11.50 - $16.90 | | | 1,091,907 | | | | 3.29 | | | | 13.48 | | | | 719,332 | | | | 13.54 | |
| $17.88 - $24.13 | | | 434,833 | | | | 0.33 | | | | 21.23 | | | | 434,833 | | | | 21.23 | |
| | | | | | | | | | | | | | | | | | | |
| | | | 3,792,623 | | | | | | | | | | | | 3,236,046 | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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, 858,750608,750 options are pledged to us to secure a repayment of debt. SeeNote 12 – Related Party Transactions.
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:
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| | | | | | | | | | | | | |
| | | 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 value of traded options that have no vesting restrictions and are fully transferable. In connection withaddition, 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 acquisitionstock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of Benton Offshore China Companyoptions granted is derived from the output of the option valuation model and represents the period of time that options are expected to be outstanding. The risk-free rate for the periods within the contractual life of the 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, 2006, 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 nonvested 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 vested during the years ended December 31, 2006, 2005 and 2004
options to purchase 74,427 shares of common stock were both outstandingwas $4.1 million, $2.7 million and
exercisable.$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 $10.88 to $11.88 which vest over three
to four years. At December 31,
2004,2006, a total of
15,00010,000 options issued outside of the plans were both outstanding and exercisable.
Note 6 — Stock Warrants The date the warrants were issued, the expiration date, the exercise price and the number of warrants issued and outstanding at December 31, 2004 were (warrants in thousands):
| | | | | | | | | | | | | | | |
| | | | | | | | | Warrants |
| Date Issued | | Expiration Date | | Exercise Price | | Issued | | Outstanding |
| June 1995 | | June 2007 | | $ | 17.09 | | | | 125 | | | | 125 | |
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Note 7 — 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
“Russia” include project evaluation costs and other costs to maintain an office in Russia. Operations included under the heading “USA“United States and Other” include corporate management, 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.
| | | | | | | | | | | | | |
| | | 2004 | | | 2003 | | | 2002 | |
Segment Revenues | | | | | | | | | | | | |
| Oil and gas sales: | | | | | | | | | | | | |
| Venezuela | | $ | 186,066 | | | $ | 106,095 | | | $ | 126,731 | |
| | | | | | | | | | |
| Total oil and gas sales | | | 186,066 | | | | 106,095 | | | | 126,731 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Segment Income (Loss) | | | | | | | | | | | | |
| Venezuela | | | 54,469 | | | | 23,874 | | | | 64,509 | |
| Russia | | | (3,524 | ) | | | (29,620 | ) | | | (2,777 | ) |
| United States and other | | | (16,585 | ) | | | 33,049 | | | | 38,630 | |
| | | | | | | | | | |
| Net income | | $ | 34,360 | | | $ | 27,303 | | | $ | 100,362 | |
| | | | | | | | | | |
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2004 | | | 2003 | |
Operating Segment Assets | | | | | | | | |
| Venezuela | | $ | 309,794 | | | $ | 241,855 | |
| Russia | | | 385 | | | | 237 | |
| United States and other | | | 108,408 | | | | 180,768 | |
| | | | | | | |
| | | | 418,587 | | | | 422,860 | |
| Intersegment eliminations | | | (51,101 | ) | | | (48,512 | ) |
| | | | | | | |
| | | $ | 367,486 | | | $ | 374,348 | |
| | | | | | | |
S-17S-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 87 — RussianVenezuela 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, formedcontractual 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
1991 to develop, produce and market crude oil from the North Gubkinskoye and South Tarasovskoye Fields in the Western Siberia region of Russia. Our minority equity investment in Geoilbent was accounted for using the equity method and was based on a fiscal year ending September 30. Sales quantities attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the year ended September 30, 2002 were 5.6 million barrels (3.3 million domestic and 2.3 million export) and 6.9 million barrels (4.6 million domestic and 2.3 million export), respectively. Prices for crude oil for the period until it was sold on September 25, 2003 and for the year ended September 30, 2002 averaged $14.52 ($8.61 domestic and $23.05 export) and $13.25 ($8.89 domestic and $21.73 export) per barrel, respectively. Depletion expense attributable to Geoilbent for the period until it was sold on September 25, 2003 and for the year ended September 30, 2002 was $3.23 and $3.93 per barrel, respectively. All amounts represent 100 percent of Geoilbent. Summarized financial information for Geoilbent follows (in thousands):| | | | | | | | | |
| Year ended September 30: | | 2003 | | | 2002 | |
| Revenues | | | | | | | | |
| Oil sales | | $ | 81,724 | | | $ | 91,598 | |
| | | | | | | |
| | | | | | | | | |
| Expenses | | | | | | | | |
| Selling and distribution expenses | | | 5,893 | | | | 6,696 | |
| Operating expenses | | | 15,897 | | | | 15,360 | |
| Depletion, depreciation and amortization | | | 18,182 | | | | 27,168 | |
| Write-downs of oil and gas properties | | | 95,000 | | | | — | |
| General and administrative | | | 9,456 | | | | 8,335 | |
| Taxes other than on income | | | 25,626 | | | | 27,657 | |
| | | | | | | |
| | | | 170,054 | | | | 85,216 | |
| | | | | | | |
| | | | | | | | | |
| Income (loss) from operations | | | (88,330 | ) | | | 6,382 | |
| |
| Other non-operating income (expense) | | | | | | | | |
| Investment earnings and other | | | 1,064 | | | | 381 | |
| Interest expense | | | (1,992 | ) | | | (4,629 | ) |
| Net gain on exchange rates | | | 1,566 | | | | 2,053 | |
| | | | | | | |
| | | | 638 | | | | (2,195 | ) |
| | | | | | | |
| | | | | | | | | |
| Income (loss) before income taxes | | | (87,692 | ) | | | 4,187 | |
| Income tax (benefit) expense | | | (3,117 | ) | | | 302 | |
| | | | | | | |
| | | | (84,575 | ) | | | 3,885 | |
| Effects of change in accounting policy | | | 310 | | | | — | |
| | | | | | | |
| Net income (loss) | | $ | (84,885 | ) | | $ | 3,885 | |
| | | | | | | |
Arctic Gas Company
On April 12, 2002, we sold our 68 percent equity interest in Arctic Gas. The equity earnings of Arctic Gas have historically been based on a fiscal year ended September 30. The fourth quarter of 2001, the first quarter of 2002 and the first twelve days of April have been included in the results for 2002.
We accounted for our interest in Arctic Gas using the equity method due to the significant influence we exercised over the operating and financial policies of Arctic Gas. Our weighted-average equity interest,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 $21.2 million, representing the
period ended April 12, 2002. Summarized financial informationsecond and third quarter advances, have been reimbursed. Harvest Vinccler invoiced PDVSA for
Arctic Gas follows (in thousands). All amounts represent 100 percentfourth quarter advances of
Arctic Gas.$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-18S-20
| | | | | |
| Year ended September 30: | | 2002 | |
| |
| Revenues | | | | |
| Oil sales | | $ | 7,880 | |
| | | | | |
| Expenses | | | | |
| Selling and distribution expenses | | | 3,170 | |
| Operating expense | | | 2,473 | |
| Depletion, depreciation and amortization | | | 333 | |
| General and administrative | | | 2,112 | |
| Taxes other than on income | | | 1,261 | |
| | | | |
| | | | 9,349 | |
| | | | |
| | | | | |
| Loss from operations | | | (1,469 | ) |
| | | | | |
| Other non-operating expense | | | | |
| Other expense | | | (4 | ) |
| Interest and foreign exchange expense | | | (1,722 | ) |
| | | | |
| | | | (1,726 | ) |
| | | | |
| | | | | |
| Loss before income taxes | | | (3,195 | ) |
| Income tax expense | | | — | |
| | | | |
| Net loss | | $ | (3,195 | ) |
| | | | |
Note 9 — Venezuela Operations
On July
At December 31,
1992, we2006, Harvest Vinccler has three loans outstanding with two Venezuelan banks for a total of 225 billion Bolivars (approximately $104.7 million). These loans are collateralized by $88.9 million deposited in two U.S. banks. The loans were used to meet the SENIAT income tax assessments 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., thenrelated interest, refinance a portion of one of
three explorationthe Bolivar loans and
production affiliates of the national oil company, PDVSA. Theto fund operating
service agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit. Under the terms of the operating service agreement, Harvest 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. Harvest 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, Harvest 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. In addition, Harvest 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.
The Venezuelan government maintains full ownership of all hydrocarbons in the fields.
We drilled ten oil wells and re-entered an additional six wells in 2004.
requirements.
Note 10 — 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. In June 2004, we sold our California onshore property, which had a zero carrying value, for net proceeds of $0.6 million. We and other parties may be responsible to the State of California for any remediation costs associated with the onshore property and the related offshore oil and gas leases.
S-19
Note 118 — 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 assessment,contract. 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. No further impairment of the property is currently required.border disputes persist. WAB-21 represents the $2.9 million excluded from the full cost pool as reflected on our December 31,
20042006 balance sheet.
Note 129 — Related Party Transactions In March 2002, we 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 Harvest Vinccler. Vinsa provided $0.3 million, $1.7 million and $0.5 million in construction services for our Venezuelan field operations for the years ended December 31, 2004, 2003 and 2002, respectively. This agreement was terminated on September 19, 2004.
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 Harvest Vinccler. Payment for services is due when earnings are not reinvested in Harvest Vinccler operations. The consulting agreement was cancelled January 1, 2004.
Expenses related to this consulting agreement were $1.5At December 31, 2006 and 2005, we owed $9.6 million and
$2.6$9.2 million,
at December 31, 2003 and 2002, 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. As of December 31, 2004, Mr. Benton’s debt balance was $2.8 million. This amount is after the payment to us in 2004 of $0.5 million from the proceeds, net of tax, of the exercise of stock options issued to Mr. Benton, but pledged to us to secure repayment of the debt, and a $0.1 million paymentrespectively, under the excess income provision of an agreement with Mr. Benton. We continue to accrue interest and provide a bad debt allowance on the remaining amount due.
consulting agreement.
Note 1310 — 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
36.137.2 million,
35.336.9 million and
34.636.1 million for the years ended December 31,
2004, 20032006, 2005 and
2002,2004, 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
38.137.2 million,
36.838.4 million
36.1and 38.1 million for the years ended December 31,
2006, 2005 and 2004,
2003 and 2002, respectively.
An aggregate of 0.91.5 million options and warrants were excluded from the earnings per share calculations because their exercise price exceeded the average price for the year ended December 31, 2004.2006. For the years ended December 31, 20032005 and 2002, 2.52004, 1.9 million and 3.50.9 million options and warrants, respectively, were excluded from the earnings per share calculations because 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-20S-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, 2004 | | | | | | | | | | | | | | | | |
| Revenues | | $ | 38,797 | | | $ | 41,397 | | | $ | 46,053 | | | $ | 59,819 | |
| Expenses | | | (20,329 | ) | | | (20,478 | ) | | | (24,697 | ) | | | (30,082 | ) |
| Non-operating income (expense) | | | (2,795 | ) | | | (2,031 | ) | | | (4,779 | ) | | | 391 | |
| | | | | | | | | | | | | |
| Income from consolidated companies before income taxes and minority interests | | | 15,673 | | | | 18,888 | | | | 16,577 | | | | 30,128 | |
| Income tax expense | | | 5,600 | | | | 9,902 | | | | 7,617 | | | | 10,169 | |
| | | | | | | | | | | | | |
| Income before minority interests | | | 10,073 | | | | 8,986 | | | | 8,960 | | | | 19,959 | |
| Minority interests | | | 2,566 | | | | 2,738 | | | | 3,654 | | | | 4,660 | |
| | | | | | | | | | | | | |
| Net income | | $ | 7,507 | | | $ | 6,248 | | | $ | 5,306 | | | $ | 15,299 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Net income per common share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.21 | | | $ | 0.17 | | | $ | 0.15 | | | $ | 0.42 | |
| | | | | | | | | | | | | |
| Diluted | | $ | 0.20 | | | $ | 0.16 | | | $ | 0.14 | | | $ | 0.39 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Other comprehensive income (loss) | | | — | | | | — | | | | (2,357 | ) | | | 1,870 | |
| | | | | | | | | | | | | |
| Total comprehensive income | | $ | 7,507 | | | $ | 6,248 | | | $ | 2,949 | | | $ | 17,169 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Quarter Ended | | | Quarter Ended | |
| | | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 | | June 30 | | September 30 | | December 31 | |
| | | (amounts in thousands, except per share data) | | | (amounts in thousands, except per share data) | |
Year ended December 31, 2003 | | |
Year ended December 31, 2006 | | |
| Revenues | | $ | 18,825 | | $ | 28,576 | | $ | 27,834 | | $ | 30,860 | | | $ | 59,172 | | $ | 334 | | $ | — | | $ | — | |
| Expenses | | | (13,901 | ) | | | (19,911 | ) | | | (20,037 | ) | | | (18,619 | ) | | | (28,143 | ) | | | (7,796 | ) | | | (7,654 | ) | | | (10,414 | ) |
| Non-operating income (expense) | | | (1,864 | ) | | | (2,288 | ) | | 44,056 | | | (1,743 | ) | | 1,940 | | | (13,419 | ) | | | (2,650 | ) | | 258 | |
| | | | | | | | | | | | | | | | | | | |
| Income from consolidated companies before income taxes and minority interests | | 3,060 | | 6,377 | | 51,853 | | 10,498 | | |
| Income before income taxes and minority interests | | | 32,969 | | | (20,881 | ) | | | (10,304 | ) | | | (10,156 | ) |
| Income tax expense | | 1,056 | | 3,104 | | 3,603 | | 1,894 | | | 14,762 | | 40,810 | | 5,338 | | 7 | |
| | | | | | | | | | | | | | | | | | | |
| Income before minority interests | | 2,004 | | 3,273 | | 48,250 | | 8,604 | | | 18,207 | | | (61,691 | ) | | | (15,642 | ) | | | (10,163 | ) |
| Minority interests | | 887 | | 1,216 | | 1,367 | | 2,498 | | | 4,339 | | | (11,409 | ) | | | (2,044 | ) | | | (1,613 | ) |
| | | | | | | | | | | |
| 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 | | | $ | 13,868 | | $ | (50,282 | ) | | $ | (13,598 | ) | | $ | (8,550 | ) |
| | | | | | | | | | | | | | | | | | | |
| | | |
| Net income (loss) per common share: | | |
| Basic | | $ | (0.44 | ) | | $ | (0.32 | ) | | $ | 1.31 | | $ | 0.22 | | | $ | 0.37 | | $ | (1.35 | ) | | $ | (0.36 | ) | | $ | (0.23 | ) |
| | | | | | | | | | | | | | | | | | | |
| Diluted | | $ | (0.44 | ) | | $ | (0.32 | ) | | $ | 1.25 | | $ | 0.21 | | | $ | 0.36 | | $ | (1.35 | ) | | $ | (0.36 | ) | | $ | (0.23 | ) |
| | | | | | | | | | | | | | | | | | | |
| | | |
| Other comprehensive income (loss) | | 2,614 | | | (3,001 | ) | | 21 | | 366 | | |
| | | | | | | | | | | |
| Total comprehensive income (loss) | | $ | (12,844 | ) | | $ | (14,414 | ) | | $ | 46,431 | | $ | 8,130 | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | 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-21S-22
TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
| | | | | | | | | | | | | | |
| | | | Venezuela | | China | | Total | |
Year Ended December 31, 2006 | | |
| Development costs | | | $ | 501 | | $ | — | | $ | 501 | |
| Exploration costs | | | — | | 35 | | 35 | |
| | | | | | | | | |
| | | | $ | 501 | | $ | 35 | | $ | 536 | |
| | | | | | | | | |
| | | |
Year Ended December 31, 2005 | | |
| Development costs | | | $ | 8,912 | | $ | — | | $ | 8,912 | |
| Exploration costs | | | — | | 42 | | 42 | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | $ | 8,912 | | $ | 42 | | $ | 8,954 | |
| | | United States | | | | | | | | | | |
| | | Venezuela | | China | | and Other | | Total | | |
Year Ended December 31, 2004 | | |
| Development costs | | $ | 39,161 | | $ | — | | $ | — | | $ | 39,161 | | | $ | 39,161 | | $ | — | | $ | 39,161 | |
| Exploration costs | | 10 | | 53 | | — | | 63 | | | 10 | | 53 | | 63 | |
| | | | | | | | | | | | | | | | | |
| | | $ | 39,171 | | $ | 53 | | $ | — | | $ | 39,224 | | | $ | 39,171 | | $ | 53 | | $ | 39,224 | |
| | | | | | | | | | | | | | | | | |
| | | |
Year Ended December 31, 2003 | | |
| Development costs | | $ | 58,079 | | $ | — | | $ | 2 | | $ | 58,081 | | |
| Exploration costs | | 11 | | 39 | | 133 | | 183 | | |
| | | | | | | | | | | |
| | | $ | 58,090 | | $ | 39 | | $ | 135 | | $ | 58,264 | | |
| | | | | | | | | | | |
| | | |
Year Ended December 31, 2002 | | |
| Development costs | �� | $ | 49,163 | | $ | 120 | | $ | 577 | | $ | 49,860 | | |
| Exploration costs | | 794 | | | (149 | ) | | 88 | | 733 | | |
| | | | | | | | | | | |
| | | $ | 49,957 | | $ | (29 | ) | | $ | 665 | | $ | 50,593 | | |
| | | | | | | | | | | |
TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):
| | | | | | | | | | | | | | |
| | | | Venezuela(a) | | China(b) | | Total | |
Year Ended December 31, 2006 | | |
| Proved property costs | | | $ | — | | $ | 13,532 | | $ | 13,532 | |
| Costs excluded from amortization | | | — | | 2,900 | | 2,900 | |
| Oilfield inventories | | | — | | — | | — | |
| Less accumulated depletion and impairment | | | — | | | (13,532 | ) | | | (13,532 | ) |
| | | | | | | | | |
| | | | $ | — | | $ | 2,900 | | $ | 2,900 | |
| | | | | | | | | |
| | | |
Year Ended December 31, 2005 | | |
| Proved property costs | | | $ | 617,137 | | $ | 13,497 | | $ | 630,634 | |
| Costs excluded from amortization | | | — | | 2,900 | | 2,900 | |
| Oilfield inventories | | | 8,150 | | — | | 8,150 | |
| Less accumulated depletion and impairment | | | | (473,496 | ) | | | (13,497 | ) | | | (486,993 | ) |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | $ | 151,791 | | $ | 2,900 | | $ | 154,691 | |
| | | United States | | | | | | | | | | |
| | | Venezuela | | China | | and Other | | Total | | |
Year Ended December 31, 2004 | | |
| Proved property costs | | $ | 608,225 | | $ | 13,454 | | $ | — | | $ | 621,679 | | | $ | 608,225 | | $ | 13,454 | | $ | 621,679 | |
| Costs excluded from amortization | | — | | 2,900 | | — | | 2,900 | | | — | | 2,900 | | 2,900 | |
| Oilfield inventories | | 6,503 | | — | | — | | 6,503 | | | 6,503 | | — | | 6,503 | |
| Less accumulated depletion and impairment | | | (432,302 | ) | | | (13,454 | ) | | — | | | (445,756 | ) | | | (432,302 | ) | | | (13,454 | ) | | | (445,756 | ) |
| | | | | | | | | | | | | | | | | |
| | | $ | 182,426 | | $ | 2,900 | | $ | — | | $ | 185,326 | | | $ | 182,426 | | $ | 2,900 | | $ | 185,326 | |
| | | | | | | | | | | | | | | | | |
| | | |
December 31, 2003 | | |
| Proved property costs | | $ | 569,055 | | $ | 13,401 | | $ | — | | $ | 582,456 | | |
| Costs excluded from amortization | | — | | 2,900 | | — | | 2,900 | | |
| Oilfield inventories | | 8,266 | | — | | — | | 8,266 | | |
| Less accumulated depletion and impairment | | | (398,206 | ) | | | (13,401 | ) | | — | | | (411,607 | ) | |
| | | | | | | | | | | |
| | | $ | 179,115 | | $ | 2,900 | | $ | — | | $ | 182,015 | | |
| | | | | | | | | | | |
| | | |
December 31, 2002 | | |
| Proved property costs | | $ | 519,175 | | $ | 26,210 | | $ | 21,030 | | $ | 566,415 | | |
| Costs excluded from amortization | | — | | 2,900 | | — | | 2,900 | | |
| Oilfield inventories | | 7,286 | | — | | — | | 7,286 | | |
| Less accumulated depletion and impairment | | | (386,824 | ) | | | (26,210 | ) | | | (20,764 | ) | | | (433,798 | ) | |
| | | | | | | | | | | |
| | | $ | 139,637 | | $ | 2,900 | | $ | 266 | | $ | 142,803 | | |
| | | | | | | | | | | |
| | |
| (a) | | Reclassified to provisional equity affiliate effective April 1, 2006.
|
|
| (b) | | SeeNotes to the Consolidated Financial Statements Note 8 – China Operations. |
S-22S-23
TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
| | | | | | | | | | | | | | | | | | | | | |
| | | | Venezuela | |
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 | | | 9,451 | |
| 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 | | | 41,175 | |
| Income tax expense | | | 65,943 | |
| | | | | |
| Total expenses | | | 147,087 | |
| | | | | |
| Results of operations from oil and natural gas producing activities | | | $ | 89,854 | |
| | | United States | | | | | | |
| | | Venezuela | | China | | and Other | | Total | | |
Year ended December 31, 2004 | | |
| Oil and natural gas revenues | | $ | 186,066 | | $ | — | | $ | — | | $ | 186,066 | | | $ | 186,066 | |
| Expenses: | | |
| Operating, selling and distribution expenses and taxes other than on income | | 33,297 | | — | | 214 | | 33,511 | | | 33,297 | |
| Depletion | | 34,108 | | — | | — | | 34,108 | | | 34,108 | |
| Income tax expense | | 38,968 | | — | | — | | 38,968 | | | 38,968 | |
| | | | | | | | | | | | | |
| Total expenses | | 106,373 | | — | | 214 | | 106,587 | | | 106,373 | |
| | | | | | | | | | | | | |
| Results of operations from oil and natural gas producing activities | | $ | 79,693 | | $ | — | | $ | (214 | ) | | $ | 79,479 | | | $ | 79,693 | |
| | | | | | | | | | | | | |
| | | |
Year ended December 31, 2003 | | |
| Oil and natural gas revenues | | $ | 106,095 | | $ | — | | $ | — | | $ | 106,095 | | |
| Expenses: | | |
| Operating, selling and distribution expenses and taxes other than on income | | 31,445 | | — | | 76 | | 31,521 | | |
| Write-down of oil and gas properties and impairments | | — | | 23 | | 142 | | 165 | | |
| Depletion | | 19,599 | | — | | — | | 19,599 | | |
| Income tax expense | | 12,158 | | — | | 1,187 | | 13,345 | | |
| | | | | | | | | | | |
| Total expenses | | 63,202 | | 23 | | 1,405 | | 64,630 | | |
| | | | | | | | | | | |
| Results of operations from oil and natural gas producing activities | | $ | 42,893 | | $ | (23 | ) | | $ | (1,405 | ) | | $ | 41,465 | | |
| | | | | | | | | | | |
| | | |
Year ended December 31, 2002 | | |
| Oil revenue | | $ | 126,731 | | $ | — | | $ | — | | $ | 126,731 | | |
| Expenses: | | |
| Operating, selling and distribution expenses and taxes other than on income | | 31,608 | | 2,493 | | — | | 34,101 | | |
| Write-down of oil and gas properties and impairments | | — | | 13,371 | | 1,166 | | 14,537 | | |
| Depletion | | 24,941 | | — | | — | | 24,941 | | |
| Income tax expense | | 4,715 | | 3 | | — | | 4,718 | | |
| | | | | | | | | | | |
| Total expenses | | 61,264 | | 15,867 | | 1,166 | | 78,297 | | |
| | | | | | | | | | | |
| Results of operations from oil and natural gas producing activities | | $ | 65,467 | | $ | (15,867 | ) | | | (1,166 | ) | | 48,434 | | |
| | | | | | | | | | | |
| | |
| (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 Harvest 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. We believe the two months representing the delay due to the time sales were halted by the civil work stoppage will be added to the original term of the operating service agreement pursuant to the force majeure provisions of the agreement.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 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-23
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,
2004, 20032005 and
20022004 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 Venezuela
and Russia 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, 2004 | | | | | | | | | | | | |
| Proved Reserves at beginning of the year | | | 87,872 | | | | (17,574 | ) | | | 70,298 | |
| Revisions of previous estimates | | | (1,578 | ) | | | 316 | | | | (1,262 | ) |
| Purchases of reserves in place | | | — | | | | — | | | | — | |
| Extensions, discoveries and improved recovery | | | — | | | | — | | | | — | |
| Production | | | (8,152 | ) | | | 1,630 | | | | (6,522 | ) |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| Proved Reserves at end of the year | | | 78,142 | | | | (15,628 | ) | | | 62,514 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
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 | |
| | | | | | | | | | | | |
S-24S-25
| | | | | | | | | | | | | |
| | | | | | | Minority | | | | |
| | | | | | | Interest in | | | | |
| | | Venezuela | | | Venezuela | | | Net Total | |
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at: | | | | | | | | | | | | |
| December 31, 2004 | | | 45,488 | | | | (9,098 | ) | | | 36,390 | |
| December 31, 2003 | | | 45,860 | | | | (9,172 | ) | | | 36,688 | |
| December 31, 2002 | | | 53,833 | | | | (10,767 | ) | | | 43,066 | |
| January 1, 2002 | | | 51,465 | | | | (10,293 | ) | | | 41,172 | |
| | | | | | | | | | | | | |
| Russia – Geoilbent (34%) Proved Reserves at end of the year 2002 | | | | | | | | | | | 11,840 | |
| | | | | | | | | | | | | |
Proved Reserves-Natural gas (MMcf) | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Year ended December 31, 2004 | | | | | | | | | | | | |
| Proved Reserves beginning of the year | | | 195,500 | | | | (39,100 | ) | | | 156,400 | |
| Revisions of previous estimates | | | (159 | ) | | | 32 | | | | (127 | ) |
| Extensions, discoveries and improved recovery | | | — | | | | — | | | | — | |
| Production | | | (31,059 | ) | | | 6,212 | | | | (24,847 | ) |
| | | | | | | | | | |
| Proved Reserves end of the year | | | 164,282 | | | | (32,856 | ) | | | 131,426 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
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 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Proved Developed Reserves-Natural gas (MMcf) at: | | | | | | | | | | | | |
| December 31, 2004 | | | 80,897 | | | | (16,179 | ) | | | 64,718 | |
| December 31, 2003 | | | 106,147 | | | | (21,229 | ) | | | 84,918 | |
| December 31, 2002 | | | 105,000 | | | | (21,000 | ) | | | 84,000 | |
| | | | | | | | | | | | | |
| | | | | | | 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 | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| | |
| (a) | | All reserves have been removed pending conversion to Petrodelta. |
| | | | | | | | | | | | | |
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 atto report under SEC guidelines and, accordingly, no reserves are reported as of December 31, 2002.2006. 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-25S-27
| | | | | | | | | | | | | |
| | | | | | | Minority | | | | |
| | | | | | | Interest in | | | | |
| | | Venezuela | | | Venezuela | | | Net Total | |
| | | (amounts in thousands) | |
December 31, 2004 | | | | | | | | | | | | |
| Future cash inflow | | $ | 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 net revenue before income taxes | | | 1,368,107 | | | | (273,621 | ) | | | 1,094,486 | |
| 10% annual discount for estimated timing of cash flows | | | (365,580 | ) | | | 73,116 | | | | (292,464 | ) |
| | | | | | | | | | |
| Discounted future net cash flows before income taxes | | | 1,002,527 | | | | (200,505 | ) | | | 802,022 | |
| Future income taxes, discounted at 10% per annum | | | (321,302 | ) | | | 64,260 | | | | (257,042 | ) |
| | | | | | | | | | |
| Standardized measure of discounted future net cash flows | | $ | 681,225 | | | $ | (136,245 | ) | | $ | 544,980 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
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 | |
| | | | | | | | | | | | |
TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Net Venezuela | | | Net Venezuela | |
| | | 2004 | | 2003 | | 2002 | | | 2006(a) | | 2005 | | 2004 | |
| | | (amounts in thousands) | | | (in thousands) | |
| Present Value at January 1 | | $ | 366,770 | | $ | 317,799 | | $ | 163,328 | | |
| Standardized Measure at January 1 | | | $ | 329,438 | | $ | 544,980 | | $ | 366,770 | |
| Sales of oil and natural gas, net of related costs | | | (122,215 | ) | | | (59,720 | ) | | | (76,098 | ) | | | (40,361 | ) | | | (124,638 | ) | | | (122,215 | ) |
| Revisions to estimates of Proved Reserves | | |
| Revisions to estimates of proved reserves | | |
| Net changes in prices, development and production costs | | 333,237 | | 76,037 | | 310,043 | | | — | | 262,852 | | 333,237 | |
| Quantities | | | (7,597 | ) | | | (1,584 | ) | | 611 | | | — | | | (365,565 | ) | | | (7,597 | ) |
| Extensions, discoveries and improved recovery, net of future costs | | — | | 4,971 | | 89,670 | | | — | | — | | — | |
| Accretion of discount | | 54,531 | | 48,128 | | 17,621 | | | — | | 80,202 | | 54,531 | |
| Net change in income taxes | | | (78,504 | ) | | | (15,053 | ) | | | (150,603 | ) | | — | | 109,030 | | | (78,504 | ) |
| Development costs incurred | | 31,329 | | 46,463 | | 40,532 | | | 501 | | 7,130 | | 31,329 | |
| Changes in timing and other | | | (32,571 | ) | | | (50,271 | ) | | | (77,305 | ) | | | (289,578 | ) | | | (184,553 | ) | | | (32,571 | ) |
| | | | | | | | | | | | | | | |
| Present Value at December 31 | | $ | 544,980 | | $ | 366,770 | | $ | 317,799 | | |
| Standardized Measure at December 31 | | | $ | — | | $ | 329,438 | | $ | 544,980 | |
| | | | | | | | | | | | | | | |
S-26
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 and the following Tables based on a fiscal period ending September 30 and, accordingly, results of operations for oil and natural gas producing activities in Russia reflect the year ended September 30, 2002.
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 | |
| | | | | | | | | | |
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 | |
| | | | | | | | | | |
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 | ) |
| | | | | | | | | | |
S-27
| | | | | | | | | | | | | |
| | | | | | | | | | | Total Equity | |
| | | Arctic Gas | | | Geoilbent | | | Affiliates | |
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 | |
| | | | | | | | | | |
TABLE IV — Quantities of Oil and Natural Gas Reserves
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Geoilbent and Arctic Gas oil and gas fields are situated on land belonging to the Government of the Russian Federation. Each obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Geoilbent had licenses to develop the North Gubkinskoye and South Tarasovskoye fields in western Siberia. Our 34 percent equity investment in Geoilbent was sold September 25, 2003. Arctic Gas had licenses to develop the Samburg and Yevo-Yakhinskiy fields in western Siberia. Arctic Gas was sold on April 12, 2002.
The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.
Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.
Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.
Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.
Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.
| | |
| (a) | | All reserves have been removed pending conversion to Petrodelta. |
S-28
| | | | | | | | | | | | | |
| | | | | | | | | | | 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 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Proved Developed Reserves at: | | | | | | | | | | | | |
| September 30, 2003 | | | — | | | | — | | | | — | |
| September 30, 2002 | | | — | | | | 13,200 | | | | 13,200 | |
| October 1, 2001 | | | 2,483 | | | | 15,658 | | | | 18,141 | |
| | | | | | | | | | | | | |
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 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Proved Developed Reserves at: | | | | | | | | | | | | |
| September 30, 2002 | | | — | | | | — | | | | — | |
| October 1, 2001 | | | 21,292 | | | | — | | | | 21,292 | |
S-29
TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
| | | | | | | | | |
| | | | | | | Total Equity | |
| | | 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 | |
| | | | | | | |
TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
| | | | | | | | | |
| | | Equity Affiliates | |
| | | 2003 | | | 2002 | |
| | | (amounts in thousands) | |
| Present Value at October 1 | | $ | 92,939 | | | $ | 152,853 | |
| Sales of oil and natural gas, net of related costs | | | (20,410 | ) | | | (23,644 | ) |
| Revisions to estimates of Proved Reserves | | | | | | | | |
| Net changes in prices, development and production costs | | | (5,522 | ) | | | 76,545 | |
| Quantities | | | 3,178 | | | | (10,007 | ) |
| Sales of reserves in place | | | (91,798 | ) | | | (82,205 | ) |
| Extensions, discoveries and improved recovery, net of future costs | | | 1,246 | | | | 2,031 | |
| Accretion of discount | | | 11,723 | | | | 7,065 | |
| Net change in income taxes | | | 1,127 | | | | 1,145 | |
| Development costs incurred | | | 4,507 | | | | 8,999 | |
| Changes in timing and other | | | 3,010 | | | | (39,843 | ) |
| | | | | | | |
| Present Value at September 30 | | $ | — | | | $ | 92,939 | |
| | | | | | | |
S-30
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: February 22, 2005March 13, 2007 | By: | /s/ Peter J. HillJames A. Edmiston | |
| | | Peter J. HillJames A. Edmiston | |
| | | 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 22nd13th day of February, 2005,March, 2007, on behalf of the registrant and in the capacities indicated:
| | | | | |
| Signature | | | | Title |
| | | | |
/s/ Peter J. HillJames A. Edmiston | | | | Director, President and Chief Executive Officer |
| | | | | |
Peter J. HillJames A. Edmiston | | | | |
| | | | | |
/s/ Steven W. Tholen Steven W. Tholen | | | | Senior Vice President — Finance, Chief Financial |
| | |
Steven W. Tholen | | Officer and Treasurer |
| (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-31
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, 2004 | | | | | | | | | | | | | | | | | | | | |
| Amounts deducted from applicable assets | | | | | | | | | | | | | | | | | | | | |
| Accounts receivable | | $ | 3,355 | | | $ | — | | | $ | — | | | $ | 598 | | | $ | 2,757 | |
| Deferred tax valuation allowance | | | 48,365 | | | | (3,284 | ) | | | — | | | | — | | | | 45,081 | |
| Investment at cost | | | 1,350 | | | | — | | | | — | | | | — | | | | 1,350 | |
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 | |
S-32
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 2004
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-term 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 consecutive 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 discussed 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 to the Company for a total value of approximately USD 1,087 thousand (2002: USD 1,752 thousand). The remaining portion of the accounts payable balance outstanding relates to services provided in prior reporting periods. As part of the sale of Harvest’s interest in the Company to YUKOS, all balances owing by the Company to Harvest were transferred to YUKOS.
Purneftegasgeologia.During 2003, 2002 and 2001, Purneftegasgeologia and affiliated entities provided services to the Company for a total value of approximately nil, USD 2,414 thousand and USD 4,193 thousand, respectively. Services consisted of drilling, well maintenance and other related work. The Company sold crude oil for a total value of USD 19 thousand and USD 24 thousand during 2003 and 2002, respectively, and materials during 2003 and 2002 for a total value of approximately USD 726 thousand and USD 613 thousand, respectively.
Purneftegas.During 2002 and 2001, Purneftegas and affiliated companies provided well maintenance services and supplies to the Company for a total of approximately USD 312 thousand and USD 248 thousand, respectively. The Company sold materials to Purneftegas and affiliated entities during 2002 for a total value of approximately USD 260 thousand.
Minley.During 2002, the Company paid USD 4.9 million to Minley in settlement at face value of promissory notes originally issued to the Company’s suppliers and contractors.
During 2003, interest expense on shareholder loans of USD 99 thousand was incurred with respect to Minley and USD 49 thousand was incurred with respect to Harvest. At 30 September 2003 interest payable to Minley totalled USD 21 thousand (2002: USD 21 thousand) and interest payable to Harvest was USD 65 thousand (2002: USD 14 thousand).
Note 16: Commitments and Contingent Liabilities
Economic and operating environment in the Russian Federation.Whilst there have been improvements in the economic situation in the Russian Federation in recent years, the country continues to display some characteristics of an emerging market. These characteristics include, but are not limited to, the existence of a currency that is not freely convertible in most countries outside of the Russian Federation, restrictive currency controls, and relatively high inflation.
The prospects for future economic stability in the Russian Federation are largely dependent upon the effectiveness of economic measures undertaken by the government, together with legal, regulatory, and political developments.
Taxation.Russian tax legislation is subject to varying interpretations and changes occurring frequently, which may be retroactive. Further, the interpretation of tax legislation by tax authorities as applied to the transactions and activity of the Company may not coincide with that of management. As a result, the tax authorities may challenge transactions and the Company may be assessed additional taxes, penalties and interest, which may be significant. The tax periods remain open to review by the tax and customs authorities for three years. The Company cannot predict the ultimate amount of additional assessments, if any, and the timing of their related settlements with certainty, but expects that additional liabilities, if any, arising will not have a significant effect on the accompanying financial statements.
Environmental matters.Environmental regulations and their enforcement are continually being considered by government authorities and the Company periodically evaluates its obligations related thereto. As obligations are determined, they are provided for over the estimated remaining lives of the related oil and gas reserves, or recognized immediately, depending on their nature. The existence of environmental liabilities under proposed or any future legislation, or as a result of stricter enforcement of existing legislation, cannot reasonably be estimated. Under existing legislation, management believes, there are no liabilities that would have a material adverse effect on the financial position, operating results or liquidity of the Company, and that have not been accrued in the financial statements.
11
LLC GEOILBENT
NOTES TO THE FINANCIAL STATEMENTS
(expressed in US Dollars except as indicated)
Note 16: Commitments and Contingent Liabilities (continued)
Oilfield licenses.The Company is subject to periodic reviews of its activities by governmental authorities with respect to the requirements of its oilfield licenses. Management of the Company correspond with governmental authorities to agree on remedial actions necessary to resolve any findings resulting from these reviews. Failure to comply with the terms of a license could result in fines, penalties or license limitation, suspension or revocation. The Company’s management believes any issues of non-compliance will be resolved through negotiations or corrective actions without any materially adverse effect on the Company’s financial position or results of operations.
Legal contingencies.The Company is claiming additional deductions relating to the fiscal periods from 1999 to 2001 amounting to approximately RR 330 million (USD 10.8 million). Management believe these deductions are permitted for companies operating in the northern regions of the Russian Federation and also deductions for certain interest paid during that period. Although the Company was successful in the initial hearing before the courts, the tax authorities have continued to challenge the Company’s position. As at 30 September 2003, the Company has not recorded any benefit relating to the above claims.
The Company is the named defendant in a number of lawsuits as well as the named party in numerous other proceedings arising in the ordinary course of business. While the outcomes of such contingencies, lawsuits or other proceedings cannot be determined at present, management believes that any resulting liabilities will not have a materially adverse effect on the operating results or the financial position of the Company.
Insurance.At 30 September 2003 and 2002, the Company held limited insurance policies in relation to its assets and operations, or in respect of public liability or other insurable risks. Since the absence of insurance alone does not indicate that an asset has been impaired or a liability incurred, no provision has been made in the financial statements for unspecified losses.
12
LLC GEOILBENT
Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)
(expressed in thousands US Dollars except as indicated)
Supplemental Information on Oil and Natural Gas Producing Activities(unaudited)
In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS No. 69”), this section provides supplemental information on the Company’s oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities:
| | | | | | | | | | | | | |
| | | Year ended | | Year ended | | Year ended |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
| Development costs | | | 10,217 | | | | 25,290 | | | | 33,774 | |
| Exploration costs | | | 3,040 | | | | 1,465 | | | | 6,100 | |
| | | |
| | | |
| | | |
| |
Total costs incurred in oil and natural gas acquisition, exploration, and development activities | | | 13,257 | | | | 26,755 | | | | 39,874 | |
| | | |
| | | |
| | | |
| |
TABLE II — Capitalized costs related to oil and natural gas producing activities:
| | | | | | | | | |
| | | As at | | As at |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
|
| Proved property costs | | | 302,214 | | | | 277,659 | |
| Costs excluded from amortisation | | | — | | | | 800 | |
| Oilfield inventories | | | 7,442 | | | | 6,905 | |
| Less accumulated depletion and impairment | | | (212,745 | ) | | | (92,470 | ) |
| | | |
| | | |
| |
Total capitalised costs related to oil and natural gas producing activities | | | 96,911 | | | | 192,894 | |
| | | |
| | | |
| |
TABLE III — Results of operations for oil and natural gas producing activities:
In accordance with SFAS 69, results of operations for oil and natural gas producing activities do not include general corporate overhead and monetary effects, nor their associated tax effects. Income tax is based on statutory rates for the year, adjusted for tax deductions, tax credits and allowances.
| | | | | | | | | | | | | |
| | | Year ended | | Year ended | | Year ended |
Thousand of US Dollars
| | 30 September 2003
| | 30 September 2002
| | 30 September 2001
|
| Oil and natural gas sales | | | 81,987 | | | | 91,291 | | | | 100,768 | |
| Expenses: | | | | | | | | | | | | |
| Operating, selling and distribution expenses and taxes other than on income | | | 47,319 | | | | 49,713 | | | | 47,302 | |
| Depletion and amortization | | | 18,278 | | | | 27,168 | | | | 14,918 | |
| Impairment of oil and gas properties | | | 95,000 | | | | — | | | | — | |
| Income tax expense | | | 6,098 | | | | 5,750 | | | | 11,006 | |
| Total expenses | | | 166,695 | | | | 82,631 | | | | 73,226 | |
| | | |
| | | |
| | | |
| |
Results of operations from oil and natural gas producing activities | | | (84,708 | ) | | | 8,660 | | | | 27,542 | |
| | | |
| | | |
| | | |
| |
13
LLC GEOILBENT
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
(expressed in thousands US Dollars except as indicated)
TABLE IV — Quantities of oil and natural gas reserves
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions.
The Company’s oil and gas fields are situated on land belonging to the Government of the Russian Federation. The Company obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Licenses will expire in September 2018 for the North Gubkinskoye field, and in March 2023 for the South Tarasovskoye field. However, under Paragraph 4 of the Russian Federal Law 20-FZ, dated 2 January 2000, the licenses may be extended over the economic life of the lease at the Company’s option. Management intends to extend such licenses for properties that are expected to produce subsequent to their expiry dates. Estimates of proved reserves extending past 2018 represent approximately 9 percent of total proved reserves.
The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and the Company considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.
Proved developed reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed 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
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.) |
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| | |
| 3.2 | | Amended and Restated Bylaws as of December 11, 2003.April 6, 2006. (Incorporated by reference to Exhibit 3.73.2 to our Form 10-K10-Q filed on March 10, 2004,April 20, 2006, File No. 1-10762.) |
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| 4.1 | | Form of Common Stock Certificate. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-26333).) |
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| 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.) |
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| 4.3 | | Second Amended and Restated Rights Agreement, dated as of September 16, 2003,April 15, 2005, between Harvest Natural Resources, Inc. and Wells Fargo Bank, Minnesota, N.A. (incorporated(Incorporated by reference to Exhibit 5 to Amendment No. 14.3 to our Registration StatementForm 10-Q filed on Form 8-A filed OctoberApril 29, 2003 (Registration2005, File No. 000-17534)1-10762.). |
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| 10.1 | | 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. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-52436).) |
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10.2 | | Note payable agreement dated March 8, 2001 between Harvest 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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10.3† | | 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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10.4 | | 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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10.5 | | 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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10.6 | | 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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10.710.5 | | 2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our S-8 (Registration Statement No. 333-85900).) |
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10.810.6 | | Addendum No. 2 to Operating service agreementService 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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10.9 | | Bank Loan Agreement between Banco Mercantil, C.A. and Harvest Vinccler C.A. dated October 1, 2002. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
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10.10 | | 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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10.1110.7†
| | 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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10.12†
| | Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.11 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
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10.13†
| | Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.12 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
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10.14†
| | Employment Agreement dated August 1, 2002 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit 10.13 to our Form 10-Q filed on November 8, 2002, File No. 1-10762.) |
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10.15 | | Sale and Purchase Agreement dated September 26, 2003, between Harvest Natural Resources, Inc. and Yukos Operational Holding Limited regarding the sale of our 34 percent minority equity investment in LLC Geoilbent. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 10, 2003, File No. 1-10762.) |
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10.16†
| | Employment Agreement dated November 17, 2003 between Harvest Natural Resources, Inc. and Karl L. Nesselrode. (Incorporated by reference to Exhibit 10.18 to our Form 10-Q filed on March 10, 2004, File No. 1-10762.) |
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10.17†
| | Employment Agreement dated September 1, 2004 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10-1 to our Form 10-Q filed on November 5, 2004, File No. 1-10762.) |
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10.18†
| | Harvest Natural Resources 2004 Long Term Incentive Plan. (Incorporated by reference to Exhibit 4.5 to our Registration Statement on Form S-8 filed on May 25, 2004 (Registration Statement No. 333-115841).) |
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| | |
10.1910.8†
| | 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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| | | |
10.2010.9†
| | Form of 2004 Long Term Stock Incentive Plan Stock Option AgreementAgreement. (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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10.2110.10†
| | Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock AgreementAgreement. (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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10.2210.11†
| | 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.) |
S-31
| 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 October 27, 2005, File No. 1-10762.) |
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| | 10.13† | | Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Steven W. Tholen. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
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| 10.14† | | Employment Agreement dated September 12, 2005 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) |
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| 10.15† | | Employment Agreement dated September 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 10.1 to our Form 10-Q filed on 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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| 10.23 | | Harvest 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.) |
S-32
| 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 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 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 SENIAT assessments. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on October 26, 2006, File No. 1-10762.) |
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| 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.) |
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| 10.31 | | Amendment 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 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 | | Certification of the Chief Executive Officer 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 of the Chief Financial Officer accompanying the annual reportAnnual Report pursuant to Section 906 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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| † | | 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. |
S-33
