þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | ||
(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) |
15835 Park Ten Place Drive, Suite 115Houston, Texas 77084(Former name, former address and former fiscal year, if changed since last report)
Title of each class | Name of each exchange on which registered | |
Common Stock, $.01 Par Value | NYSE |
Title of each class | Name of each exchange on which registered | |
None | None |
Large Accelerated Filero | Accelerated Filerþ | Non-Accelerated Filer o | Smaller Reporting Companyo |
State the
29, 2007 was: $444,689,722.
35,050,833.
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2007.
As of December 31, 2004,2007, we had total assets of $367.5 million. We had$413.4 million, unrestricted cash in the amount of $84.6$120.8 million and no long-term debt. WeFor the year ended December 31, 2007, we had total revenues of $186.1$11.2 million and
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Our strategy has broadened from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business strategydevelopment and technical platform to create a diversified resource base. With the addition of technical resources, opening of our London office, the planned 2008 opening of a Singapore office, the redeployment of resources from our Moscow office, as well as our earlier purchase of a 45 percent equity interest in Fusion Geophysical, L.L.C. (“Fusion”), we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. While exploration will become a larger part of our overall portfolio, we will generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles.
In Venezuela, we seekreceipt of a dividend from Petrodelta as well as the need to deliver maximum operating cash flow throughpreserve adequate development capital in the efficient management of our capital expenditure programs and cost structure.interim.
We have significant financial flexibility and substantial cash flow supported by current oil prices and current production levels for both oil and gas. We believe this provides us with the ability to pursue growth opportunities while at the same time maintaining a strong balance sheet. However, we have recently experienced difficulties in Venezuela with getting our budgets approved and obtaining permits from the Ministry of Energy and Petroleum (“MEP”, formerly Ministry of Energy and Mines) and Ministry of Environment, as required, which are critical to our ability to fully execute our drilling program. A continuation of these difficulties or a curtailment of production in Venezuela could adversely affect our production and our ability to pursue growth opportunities.
While we cannot predict the degree to which we will be successful, we continue to evaluate properties in both Venezuela and Russia to find opportunities which meet our focused acquisition criteria. We expect our cash generating capacity to be supported by our new gas production, lower operating expenses and our expected future Uracoa and Bombal drilling programs.
Our ability to successfully execute our strategy is subject to significant risks including, among other things, payment of Petrodelta dividends, exploration, operating, risks, political, risks, legal risks and financial risks. SeeItem 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.
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The following table summarizes
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.
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Geoilbent | ||||||||
Year Ended September 30, | ||||||||
2003 | 2002 | |||||||
(Dollars in 000’s) | ||||||||
RESERVE INFORMATION: | ||||||||
Proved Reserves (MBbls) | (a | ) | 25,356 | |||||
Discounted future net cash flow attributable to proved reserves, before income taxes | (a | ) | $ | 117,229 | ||||
Standardized measure of discounted future net cash flows | (a | ) | $ | 92,939 | ||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||
Gross development wells drilled | (a | ) | 6 | |||||
Net development wells drilled | (a | ) | 2 | |||||
Average daily production (Bbls) | 5,242 | 6,438 | ||||||
FINANCIAL DATA: | ||||||||
Oil and natural gas revenues | $ | 27,876 | $ | 31,039 | ||||
Expenses: | ||||||||
Operating, selling and distribution expenses and taxes other than on income | 16,088 | 16,902 | ||||||
Depletion | 6,215 | 9,237 | ||||||
Write-down of oil and gas properties | 32,300 | — | ||||||
Income tax expense | 2,073 | 1,955 | ||||||
Total expenses | 56,676 | 28,094 | ||||||
Results of operations from oil and natural gas producing activities | $ | (28,800 | ) | $ | 2,945 | |||
We owned, free The Board of Directors of Petrodelta consists of five directors, three of whom are appointed by CVP, including the President of the Board, and two of whom are appointed by HNR Finance. Decisions of the Board of Directors are taken by the favorable vote of at least three of its members, except in the case of any sale and transfer restrictions, until it was sold on April 12, 2002, 39 percentdecision implementing a decision of the equity interestsShareholders’ Meeting relating to any of the matters where a qualified majority is required, in Arctic Gas, which we accountedcase, 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 Bylaws. 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 Charter and Bylaws; agreeing on contracts consistent with the work programs and budgets; opening and closing bank accounts; making, accepting, endorsing and guaranteeing bank drafts and other commercial instruments consistent with work programs and budgets; and implementing policies and procedures.
Arctic Gas Company | ||||
Year Ended | ||||
September 30, 2002 | ||||
(Dollars in 000’s) | ||||
RESERVE INFORMATION: | ||||
Proved Reserves (MBoe) | (a | ) | ||
Discounted future net cash flow attributable to proved reserves, before income taxes | (a | ) | ||
Standardized measure of discounted future net cash flows | (a | ) | ||
DRILLING AND PRODUCTION ACTIVITY: | ||||
Gross wells reactivated | (a | ) | ||
Average daily production (Bbls) | 189 | |||
FINANCIAL DATA: | ||||
Oil and natural gas revenues | $ | 3,554 | ||
Expenses: | ||||
Selling and distribution expenses | 1,429 | |||
Operating expenses and taxes other than on income | 1,673 | |||
Depletion | 139 | |||
Income tax expense | 19 | |||
Total expenses | 3,260 | |||
Results of operations from oil and natural gas producing activities | $ | 294 | ||
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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 Bombal fields. These fields comprise the South Monagas Unit. We were the first U.S. company since 1976 to be granted such an oil field development contract in Venezuela.
Thecrude oil and natural gas operationsliquids delivered, and in Bolivars in the South Monagas Unit are conducted by Harvest Vinccler, our 80 percent-owned subsidiary. The remaining 20 percentcase of the outstanding capital stock of Harvest Vinccler is owned by Vinccler. Through our majority ownership of stock in Harvest Vinccler, we make all operational and corporate decisions related to Harvest Vinccler, subject to certain super-majority provisions of Harvest Vinccler’s charter documents related to:
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.
Under the terms of the operating service agreement, Harvest Vinccler is a contractor for PDVSA. Harvest Vinccler is responsible for overall operations of the South Monagas Unit, including all necessary investments to reactivate and develop the fields comprising the South Monagas Unit. The Venezuelan government maintains full ownership of all hydrocarbons in the fields. In addition, PDVSA maintains full ownership of equipment and capital infrastructure following its installation.
The operating service agreement 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. The maximum total fee is subject to quarterly adjustments to reflect changes in the average of certain world crude oil prices. Since 1992, the maximum total fee received by Harvest Vinccler has approximated 48 percent of West Texas Intermediate crude oil (“WTI”) price.
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. For 2004, natural gas sales averaged 85 million cubic feet (“MMcf”) per day. In addition, Harvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production (“Incremental Crude Oil”). Incremental Crude Oil is sold at a price of $7.00 per barrel with the quarterly volume of such sales based on quarterly natural gas sales multiplied by the ratio of 4.5 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 invoicespayment for natural gas sales and Incremental Crude Oil. Payment is due underdelivered, in immediately available funds to the invoicesbank accounts designated by the endPetrodelta. Any dividend paid by Petrodelta will be made in U.S. Dollars.
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Harvest Vinccler has constructed a 25-mile oil pipeline from its oil processing facilities at UracoaConversion Contract is attached 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 MMcf of natural gas per day and a design capacity of 90 MMcf of natural gas per day, a gas gathering system, upgrades to the UM-2 plant facilities and new gas treatment and compression facilities. Harvest Vinccler borrowed $15.5 million under a project loanour Quarterly Report on Form 10-Q 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 to PDVSA.
In August 1999, Harvest Vinccler sold its power generation facility located in the Uracoa and Tucupita Fields. Concurrentlyquarter ended September 30, 2007 filed with the sale, Harvest Vinccler entered into a long-term power purchase agreement with the purchaser of the facility to provide for the electrical needs of the field throughout the remaining term of the operating service agreement. Harvest Vinccler has entered into long-term agreements for the leasing of compression and the operation and maintenance of the gas treatment and compression facilities.
Risk Factors
Currently, the production from the South Monagas Unit represents all of our production. This production may be reduced by actions of the Venezuelan government. In addition, political uncertainty in Venezuela increases our exposure to production disruptions and project execution risk. These risk factors and other risk factors are discussed in Item 7,Risk Factors.
SEC on November 1, 2007.
The
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.
Uracoa Field
Harvest Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa 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 VincclerPetrodelta is produced from the Uracoa Field.
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Tucupita Field
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.
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Customers
UnderLifting Cost Summary
Employeesprices and Community Relations
Harvest Vinccler has a highly skilled staff of 219 local employees and two expatriates. Harvest Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care, as well as additional social investments includingaverage operating expenses for the purchase of medicines and medical equipment for local communities within the South Monagas Unit.
Health, Safety and Environment
Harvest Vinccler’s health, safety and environmental policy is an integral part of its business. Harvest Vinccler continually improves its policy and practices related to personnel safety, property protection and environmental management. These improvements can be directly attributed to its efforts in accident prevention programsyear ended December 31, 2007 and the trainingperiod April 1, 2006 through December 31, 2006 for Petrodelta. The presentation for Petrodelta includes 100 percent of the production (in thousands, except per unit information).
Year Ended | Nine Months Ended | |||||||
December 31, 2007 | December 31, 2006 | |||||||
Venezuela | ||||||||
Crude Oil Sales (Bbls) | 5,374 | 5,211 | ||||||
Natural Gas Sales (Mcf) | 13,456 | 11,519 | ||||||
Average Crude Oil Sales Price ($per Bbl) | $ | 58.61 | $ | 50.98 | ||||
Average Natural Gas Sales Price ($per Mcf) | $ | 1.54 | $ | 1.54 | ||||
Average Operating Expenses ($per Boe) | $ | 3.12 | $ | 3.19 |
North GubkinskoyeDecember 31, 2007:
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Petrodelta | 16,432 | 6,573 | 230,672 | 92,269 | ||||||||||||
In September 2003, we soldeconomic benefits of our 34 percent minority equity investmentownership in GeoilbentPetrodelta from April 1, 2006 through December 31, 2007 in the fourth quarter of 2007 as Net Income from Unconsolidated Equity Affiliates. Petrodelta’s results and operating information is more fully described inPart IV, Item 15, Notes to Yukos Operational Holding Limited for $69.5 million plus $5.5 million for the repaymentConsolidated Financial Statements, Note 7 – Venezuela Operations – Petrodelta, S.A.
East Urengoy, Russia (Arctic Gas Company)
Arctic Gas Company was sold in April 2002. SeeNote 8 – Russian Operations.
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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.
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zones similar to the known fields and discoveries.
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.
Activities by Area
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 Reservesconcession as of December 31, 2004 and 2003 were prepared by Ryder Scott Company, L.P., independent2007:
Undeveloped | ||||||||
Gross | Net | |||||||
China | 7,470,080 | 7,470,080 | ||||||
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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 | |||||||||
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:
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.
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 ofFebruary 2008, Indonesia’s oil and gas properties.regulatory authority, BP Migas, approved the assignment to us of a 47 percent interest in the Budong PSC located onshore West Sulawesi, Indonesia. Final government approval from Migas is pending. The 10 percent discount factorBudong PSC includes a ten-year exploration period and a 20-year development phase. In the initial three-year exploration phase, which began January 2007, we expect to acquire, process and interpret approximately 500 kilometers of 2-D seismic and drill two exploration wells. Our partner, Tately Budong-Budong N.V. (“Tately”), will be the operator through the exploration phase as required by the SECterms of the Budong PSC. We will have control of major decisions and financing for the project with an option to be usedoperate in the development and production phase if approved by BP Migas.
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Production, Prices and Lifting Cost Summary
In the following table we have set forth by country our net production, average sales prices and average operating expenses for the years ended December 31, 2004, 2003 and 2002. The presentation for Venezuela includes 100 percentunderstanding of the production, without deduction for minority interest. Geoilbent (34 percent ownership)geology and Arctic Gas (39 percent ownership not subject to any sale or transfer restrictions at December 2001), which are accounted for underenhanced the equity method,prospectivity of the offshore WSFB and, by analogy, the sparsely explored onshore area.
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 | ) |
Regulation
General
Our operationsour ability to finance and fund our growth strategy are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:
• | change in governments; | |||
• | civil unrest; | |||
• | price and currency controls; | |||
• | limitations on oil and natural gas production; | |||
• | ||||
tax, environmental, safety and other laws relating to the petroleum industry; | ||||
• | changes in | |||
• | changes in administrative regulations and the interpretation and application of such rules and regulations; and | |||
• | changes in contract interpretation and policies of contract adherence. |
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of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business.
Venezuela
On February 5, 2003, Venezuela imposed currency controlsbusiness and created the Commissionour potential 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. Initially the exchange rate was set at 1,600 Venezuelan Bolivars for each U.S. Dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. Dollar. Oil companies such as 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. No capital expenditures to comply with environmental regulations were required in 2003 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. 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) $39.2 million, $58.3 million and $50.6 million in 2004, 2003 and 2002, respectively. Included in these numbers is $33.5 million, $43.6 million and $44.3 million for the development of Proved Undeveloped Reserves in 2004, 2003 and 2002, respectively.
We have drilled or participated through our equity affiliate in the drilling of wells as follows:economic loss.
Year Ended December 31, | ||||||||||||||||||||||||
2004 | 2003 | 2002 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Wells Drilled: | ||||||||||||||||||||||||
Exploration: | ||||||||||||||||||||||||
Dry hole | — | — | — | — | 1 | 0.4 | ||||||||||||||||||
Development: | ||||||||||||||||||||||||
Crude oil | 16 | 12.8 | 3 | 2.4 | 18 | 12.0 | ||||||||||||||||||
Total | 16 | 12.8 | 3 | 2.4 | 19 | 12.4 | ||||||||||||||||||
Average Depth of Wells (Feet) | 5,443 | 6,095 | 7,341 | |||||||||||||||||||||
Producing Wells(1): | ||||||||||||||||||||||||
Crude Oil | 124 | 99.2 | 111 | 88.8 | 258 | 158.2 |
All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not directly operate any drilling equipment.
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Acreage
The following table summarizes the developed and undeveloped acreage that we owned, leased or held under operating service agreement or concession as of December 31, 2004:
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.
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Title
All Venezuelanequipment 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.
• | 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; |
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• | delays in receipt of permits or access to lands; and | ||
• | government actions or changes in regulations. |
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The WAB-21 petroleum contract lies within an areaoil. To the extent that market values of oil decline, the business plan of Petrodelta may be adversely affected.
• | 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
13
We are unable to estimate the amount or range of any possible loss.
• | Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the OSA. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims. | ||
• | Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims. | ||
• | Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest |
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Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim. | |||
• | Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims. |
• | One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. | ||
• | Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims. | ||
• | Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims. |
None.
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and Issuer Purchases of Equity Securities
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 | |||||||
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 | ||||||||
2007 | First quarter | $ | 10.46 | $ | 9.11 | |||||
Second quarter | 13.50 | 9.37 | ||||||||
Third quarter | 12.89 | 10.00 | ||||||||
Fourth quarter | 14.00 | 12.13 |
Number of Securities | ||||||||||||
Remaining | ||||||||||||
Number of | Available for | |||||||||||
Securities to be | Weighted | Future Issuance | ||||||||||
Issued upon | Average | Under Equity | ||||||||||
Exercise of | Exercise Price | Compensation | ||||||||||
Outstanding | Of Outstanding | Plans (Excluding | ||||||||||
Options, Warrants | Options, Warrants | Securities Reflected | ||||||||||
And Rights | And Rights | in Column (a)) | ||||||||||
PLAN CATEGORY | (a) | (b) | (c) | |||||||||
Equity compensation plans approved by security holders | 3,702,160 | $ | 8.55 | 620,940 | ||||||||
Equity compensation plans not approved by security holders (1) | 519,650 | $ | 2.69 | — | ||||||||
Total | 4,221,810 | $ | 7.83 | 620,940 | ||||||||
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(1) | SeePart IV, Item 15, Notes to the Consolidated Financial Statements, Note 5 – Stock Option and Stock Purchase Plansfor a description of options issued to individuals other than our officers, directors or employees. The 1999 Stock Option Plan permits the granting of stock options to purchase up to 2,500,000 shares of our common stock in the form of ISOs, NQSOs or a combination of each, with exercise prices not less than the fair market value of the common stock on the date of the grant, subject to the dollar limitations imposed by the Internal Revenue Code. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. Options granted to employees under the 1999 Stock Option Plan vest 50 percent after the first year and 25 percent after each of the following two years, or they vest ratably over a three-year period, from their dates of grant and expire ten years from grant date or three months after retirement, if earlier. All options granted to outside directors and consultants under the 1999 Stock Option Plan vest ratably over a three-year period from their dates of grant and expire ten years from grant date. These were the only compensation plans in effect that were adopted without the approval of our stockholders. |
2002 | 2003 | 2004 | 2005 | 2006 | 2007 | |||||||||||||||||||||||||||
Harvest Natural Resources, Inc. | $ | 100 | $ | 154 | $ | 268 | $ | 138 | $ | 165 | $ | 190 | ||||||||||||||||||||
Dow Jones US E&P Index | $ | 100 | $ | 129 | $ | 182 | $ | 298 | $ | 312 | $ | 403 | ||||||||||||||||||||
S&P 500 Index | $ | 100 | $ | 126 | $ | 138 | $ | 142 | $ | 161 | $ | 167 | ||||||||||||||||||||
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15
Year Ended December 31, | ||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||
Statement of Operations: | ||||||||||||||||||||
Total revenues | $ | 186,066 | $ | 106,095 | $ | 126,731 | $ | 122,386 | $ | 140,284 | ||||||||||
Operating income | 90,480 | 33,627 | 34,585 | 28,201 | 53,204 | |||||||||||||||
Net income | 34,360 | 27,303 | 100,362 | 43,237 | 20,488 | |||||||||||||||
Net income per common share: | ||||||||||||||||||||
Basic | $ | 0.95 | $ | 0.77 | $ | 2.90 | $ | 1.27 | $ | 0.67 | ||||||||||
Diluted | $ | 0.90 | $ | 0.74 | $ | 2.78 | $ | 1.27 | $ | 0.66 | ||||||||||
Weighted average common shares outstanding | ||||||||||||||||||||
Basic | 36,128 | 35,332 | 34,637 | 33,937 | 30,724 | |||||||||||||||
Diluted | 38,122 | 36,840 | 36,130 | 34,008 | 30,890 |
Year Ended December 31, | ||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Total assets | $ | 367,486 | $ | 374,348 | $ | 335,192 | $ | 348,151 | $ | 286,447 | ||||||||||
Long-term debt, net of current maturities | — | 96,833 | 104,700 | 221,583 | 213,000 | |||||||||||||||
Stockholders’ equity(1) | 243,189 | 199,713 | 171,317 | 67,623 | 12,904 |
Year Ended December 31, | ||||||||||||||||||||
2007(1) | 2006(1) | 2005 | 2004 | 2003 | ||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||
Statement of Operations: | ||||||||||||||||||||
Total revenues | $ | 11,217 | $ | 59,506 | $ | 236,941 | $ | 186,066 | $ | 106,095 | ||||||||||
Operating income (loss) | (19,536 | ) | 574 | 104,571 | 70,547 | 13,930 | ||||||||||||||
Net income from Unconsolidated Equity Affiliates | 51,695 | — | — | — | — | |||||||||||||||
Net income (loss) | 57,237 | (62,502 | ) | 38,876 | 18,414 | 11,545 | ||||||||||||||
Net income (loss) per common share: | ||||||||||||||||||||
Basic | $ | 1.57 | $ | (1.68 | ) | $ | 1.05 | $ | 0.51 | $ | 0.33 | |||||||||
Diluted | $ | 1.51 | $ | (1.68 | ) | $ | 1.01 | $ | 0.48 | $ | 0.31 | |||||||||
Weighted average common shares outstanding | ||||||||||||||||||||
Basic | 36,550 | 37,225 | 36,949 | 36,128 | 35,332 | |||||||||||||||
Diluted | 37,950 | 37,225 | 38,444 | 38,122 | 36,840 |
Year Ended December 31, | ||||||||||||||||||||
2007(1) | 2006(1) | 2005 | 2004 | 2003 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Total assets | $ | 413,469 | $ | 468,365 | $ | 451,377 | $ | 433,019 | $ | 459,814 | ||||||||||
Long-term debt, net of current maturities | — | 66,977 | — | — | 96,833 | |||||||||||||||
Stockholders’ equity | 313,766 | 281,409 | 337,975 | 295,615 | 268,086 |
(1) | Activities under our OSA are reflected under the equity method of accounting effective April 1, 2006. The results of Petrodelta’s operations from April 1, 2006 until December 31, 2007 are reflected in 2007 when Petrodelta was formed. |
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19
Business Strategy
We intend
• | maintain financial prudence and | ||
• | access capital markets; | ||
• | create a diversified portfolio of assets; | ||
• | preserve our financial flexibility; | ||
• | use our experience and skills to acquire new projects; and | ||
• | keep our organizational capabilities in line with our rate of growth. |
20
To accomplish our strategy, we intend to: | |||
• | Diversify our political risk:Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our investment portfolio. | ||
• | Seek Operational | ||
• | Establish a | ||
• | Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital |
16
maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure.
• | Provide Technical Expertise:We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally. In addition to our in-house technical capabilities, in January 2007 we acquired a minority interest in Fusion, 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 strategic access to these services. | ||
• | Maintain A Prudent |
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 revenueaccess to debt 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:
• | Manage Exploration Risks. We seek to manage the higher risk of exploration by diversifying our prospect portfolio, applying state-of-the-art technology for analyzing targets and focusing on opportunities in proven active hydrocarbon systems with infrastructure. | |||
• | ||||
expect to monetize production through operations or the | ||||
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Estimatesten-year exploration period and a 20-year development phase. In the initial three-year exploration phase, which began January 2007, we expect to acquire, process and interpret approximately 500 kilometers of oil2-D seismic and natural gas reserves are uncertain and inherently imprecise. This Form 10-K contains estimates of our proved oil and natural gas reserves anddrill two exploration wells. Tately will be the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptionsoperator through the exploration phase as 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 actionsterms of the Venezuelan Government.
The processBudong PSC. We will have control of estimating oil and natural gas reserves is complex. Such process requires significantmajor decisions and assumptionsfinancing for the project with an option to operate 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 phase if approved by BP Migas. The Budong PSC covers 1.35 million acres and includes the Lariang and Karama sub-basins which are the eastern onshore extension of the WSFB. Exploration to date in the basin is immature due to previously difficult jungle terrain, which is now accessible with the development of palm oil and gas properties will affect the timing of actual future net cash flows from estimated proved reservesplantations and their present value. In addition,related infrastructure. Field work performed over the last 10 percent discount factor, which is required byyears, as outcrops have been more accessible, has given a new understanding to the SEC to be used in calculating discounted future net cash flows for reporting purposes, ispresence of Eocene source and reservoir potential that had not necessarilypreviously been recognized. Recent seismic surveys have greatly improved 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 accuracyunderstanding of the 10 percent discount factor.
We may not be able to replace production with new reserves. In general, production ratesgeology and remaining reserves from oilenhanced the prospectivity of the offshore WSFB and, gas properties decline as reserves are depleted. The decline rates depend on reservoir characteristics. Our reserves inby analogy, 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 levelsparsely explored onshore area. To date, a total 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 weeight leads have been recognized. It will be ablenecessary to drill productive wells at acceptable costs.
Our operations are subjectacquire a grid of seismic data to numerous risksconfirm the structures and give an indication of oilEocene target(s) within the section and natural gas drillingto mature these leads into drillable prospects. The two identified sub-basins (Lariang and production activities.Oil and natural gas drilling and production activities are subjectKarama) provide an opportunity 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
2022
often uncertain. Oil and natural gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
The prevailing price of oil also affects the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.
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
You should read themonth period ending December 31, 2007, comparatively.
21
Years Ended December 31, 2007 and 2006
Years Ended December 31, | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
Operating Expenses | 18 | % | 29 | % | 27 | % | ||||||
Depletion, Depreciation and Amortization | 19 | 20 | 21 | |||||||||
General and Administrative | 12 | 15 | 13 | |||||||||
Taxes Other Than on Income | 3 | 3 | 3 | |||||||||
Interest | 4 | 10 | 13 |
Yearsyear ended December 31, 20042007 reflects the reversal of deferred revenue recorded by Harvest Vinccler for 2005 and 2003
Net income for 2004 was $34.4 million, or $0.90 per diluted share, compared with $27.3 million, or $0.74 per diluted share for 2003.
Our resultsfirst quarter of operations for 2004 primarily reflected2006 deliveries pending clarification on the results for Harvest-Vinccler in Venezuela, which accounted for allcalculation of our productioncrude prices under the Transitory Agreement. SeePart IV, Item 15, Notes to the Consolidated Financial Statements, Note 1 – Organization and Summary of Significant Account Policies – Revenue Recognition. There were no sales of oil and natural 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 was2007 due to the additionconversion 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 duethe OSA 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 productionminority equity interest in Venezuela from December 2002 to February 2003 due to the national work stoppage.
Our operatingPetrodelta.
Year Ended | ||||||||||||
December 31, | Increase | |||||||||||
2007 | 2006 | (Decrease) | ||||||||||
General and administrative | $ | 29.7 | $ | 26.4 | $ | 3.3 | ||||||
Contribution to Science and Technology Fund | — | 3.9 | (3.9 | ) | ||||||||
Taxes other than on income | 0.4 | 3.9 | (3.5 | ) | ||||||||
Gain on financing transactions | (49.6 | ) | — | (49.6 | ) | |||||||
Investment income and other | (9.1 | ) | (9.4 | ) | 0.3 | |||||||
Interest expense | 8.2 | 23.2 | (15.0 | ) | ||||||||
Net (gain) loss on exchange rates | — | 0.1 | (0.1 | ) |
Taxes other than on income increased $2.2 million, or 65 percent, during 2004 compared with 2003. This was primarily due to increased Venezuelan municipal taxes which result from higher oil and gas revenues.
Investment income and other increased $0.7 million, or 47 percent, during 2004 compared with 2003. This was due to higher interest rates earned on average cash balances. Interest expense decreased $2.7 million, or 26 percent, during 2004 compared with 2003 due to lower average outstanding debt balances for 2004 compared to 2003. In 2004, we redeemed all $85 million of our 2007 Notes, and we repaid all Bolivar denominated debt in March 2003.
Net gain (loss) on exchange rates decreased $1.2 million, or 218 percent, for 2004 compared with 2003. This was due to the significant devaluation of the Bolivar and Bolivar currency controls imposed in February 2003 which fixed the exchange rate between the Bolivar and the U.S. Dollar and restricts the ability to exchange Venezuelan Bolivars for dollars and vice versa.
22
We realized income before income taxes and minority interest of $81.3 million during 2004 compared with income of $71.8 million in 2003. The increase was primarily attributable to higher crude oil and natural gas volumes and an increase in crude oil price in 2004expenses offset by lower contract services. During 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.
Yearsyear ended December 31, 20032007, we recorded a gain of $49.6 million as a result of the purchase 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 dueU.S. Dollar indexed Venezuelan government bonds (seePart IV, Item 15, Notes 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 continuedConsolidated Financial Statements, Note 12 – Gain on Financing Transaction). There were no such financing transactions entered into 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.
year ended December 31, 2006. Taxes other than on income decreased $0.7 million, or 17 percent, during 2003 compared with 2002. This was primarily due to decreased Venezuelanthe elimination of municipal taxes which result from lowerwere based on oil revenues partially offset by a one-time adjustment of U.S. employment taxes of $0.7 million in 2002.
deliveries under the OSA.
23
balances
Net gain on exchange rates decreased $4.0$38.9 million, or 88 percent,$1.05 diluted earnings per share, for 20032005.
Year Ended | ||||||||||||
December 31, | Increase | |||||||||||
2006 | 2005 | (Decrease) | ||||||||||
General and administrative | $ | 26.4 | $ | 22.8 | 3.6 | |||||||
Contribution to Science and Technology Fund | 3.9 | — | 3.9 | |||||||||
Account receivable write-off on retroactive oil price adjustment | — | 4.5 | (4.5 | ) | ||||||||
Taxes other than on income | 3.9 | 6.4 | (2.5 | ) | ||||||||
Investment income and other | (9.4 | ) | (4.2 | ) | (5.2 | ) | ||||||
Interest expense | 23.2 | 3.4 | 19.8 | |||||||||
Net (gain) loss on exchange rates | 0.1 | (2.8 | ) | 2.9 |
We realized income before income taxesfinancing capabilities, and minority interestthat there may be operational or contractual consequences to this inability. In addition, our ability to explore and develop growth opportunities outside of $71.8 million during 2003 compared with income of $169.8 million in 2002. The decrease was primarily attributableVenezuela is dependent upon the ability to the Arctic Gas Sale in 2002 offset by the sale of our minorityreceive 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.
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On February 5, 2003, the Government of Venezuela fixed the exchange rate between the Bolivar and the U.S. Dollar, and restricted the ability to exchange Venezuelan Bolivars for U.S. Dollars and vice versa. Initially the exchange rate was fixed at 1,600 Venezuelan Bolivars for each U.S. Dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. Dollar. Oil companies, such as 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.
expenditures. Our ability to replace production with new reservesacquire and develop growth opportunities outside of Venezuela is dependent upon the ability ofto receive dividends from Petrodelta and access debt and equity markets.
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 ofhas debt of $2.920 billion Bolivars (approximately $9.3 million) which is secured by $6.8 million which includes the $1.3 million prepayment call premium, $0.7 million for interest related to the period October 1, 2004 to
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November 1, 2004 and $0.9 million write-off of unamortizedin restricted cash deposited in a U.S. bank. We have no other 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.
obligations.
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.
pay dividends.
Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
(in thousands) | (in thousands except as indicated) | |||||||||||||||||||||||
2004 | 2003 | 2002 | 2007 | 2006 | 2005 | |||||||||||||||||||
Net cash provided by operating activities | $ | 74,140 | $ | 38,538 | $ | 42,627 | ||||||||||||||||||
Net cash provided by (used in) operating activities | $ | (20,451 | ) | $ | (24,448 | ) | $ | 114,665 | ||||||||||||||||
Net cash provided by (used in) investing activities | (39,684 | ) | 38,191 | 126,143 | 69,756 | (90,556 | ) | (15,647 | ) | |||||||||||||||
Net cash used in financing activities | (88,516 | ) | (2,570 | ) | (113,293 | ) | ||||||||||||||||||
Net cash provided by (used in) financing activities | (76,543 | ) | 100,064 | (20,599 | ) | |||||||||||||||||||
Net increase (decrease) in cash | $ | (54,060 | ) | $ | 74,159 | $ | 55,477 | $ | (27,238 | ) | $ | (14,940 | ) | $ | 78,419 | |||||||||
Working Capital | 111,534 | 117,564 | 178,074 | |||||||||||||||||||||
Current Ratio | 3.6 | 2.4 | 3.9 | |||||||||||||||||||||
Total Cash, including restricted cash | 127,610 | 236,968 | 163,019 | |||||||||||||||||||||
Total Debt | 9,302 | 104,651 | 5,467 | |||||||||||||||||||||
Percent of total debt to capitalization | 3 | % | 27 | % | 2 | % |
At December 31, 2004, we had current assets of $172.2 million and current liabilities of $83.2 million, resulting in working capital of $89.0 million and a current ratio of 2:1. This compares with a working capital of $137.2 million and a current ration of 4:1 at December 31, 2003.
the SENIAT for 2001 through first quarter of 2006.
2006.
The timing and size of capital expenditures for the South Monagas Unit are largely at our discretion, although PDVSA has recently attempted to limit Harvest Vinccler’s capital spending (seeRisk Factors). Our remainingPetrodelta, capital commitments worldwidefor Petrodelta will 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 to date support our search for new acquisitions, are relatively minimal
25
returned to us.
25
repaid all of its borrowed 11 billion Bolivars (approximately $5.0 million) for short term Bolivar denominated debt ($2.2obligations, 105 billion Bolivars (approximately $48.8 million) and $1.220 billion Bolivars (approximately $9.3 million) for the SENIAT income tax assessments and related interest and 120 billion Bolivars (approximately $55.8 million) for the SENIAT income tax assessments and related interest, to refinance previous borrowings and for operational needs. Also during the year ended December 31, 2006, Harvest Vinccler repaid $5.5 million of its U.S. Dollar debt which was(one payment of $0.3 million and four payments of $1.3 million each on the variable rate loans) and 31 billion Bolivars (approximately $14.3 million) of its Bolivar debt.
$11.09 per share, including commissions. At December 31, 2007, we had approximately 34.8 million shares outstanding.
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 | $ | — | $ | — | $ | — | $ | 9,302 | $ | 9,302 | $ | — | $ | — | $ | — | ||||||||||||||||||||
Building Lease | 3,117 | 415 | 421 | 388 | 1,893 | 1,795 | 342 | 333 | 216 | 904 | ||||||||||||||||||||||||||||||
Total | $ | 14,950 | $ | 12,248 | $ | 421 | $ | 388 | $ | 1,893 | $ | 11,097 | $ | 9,644 | $ | 333 | $ | 216 | $ | 904 | ||||||||||||||||||||
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.
Dividends from Petrodelta will be denominated in U.S. Dollars when paid. 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
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26
An exemption under the Venezuelan Criminal Exchange Law for transactions in certain securities results in an indirect securities transaction market of foreign currency exchange, through which companies may obtain foreign currency legally without requesting it from the Venezuelan government. Publicly available quotes do not exist for the securities transaction exchange rate but such rates may be obtained from brokers. Securities transaction markets are used to move financial securities in and out of Venezuela.
OilDecember 31, 2007 is reflected in the fourth quarter of 2007 consolidated statement of operations. These investments are increased or decreased by earnings/losses and natural gas revenue is accrued monthly based on sales. Each quarter, Harvest Vinccler invoices PDVSA based on barrels of oil accepteddecreased by PDVSA during the quarter, using quarterly adjusted U.S. Dollar contract service fees per barrel.
dividends paid. No dividends were declared or paid by Fusion or Petrodelta in 2007.
We follow
The full costan accepted 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 sensitivethe successful efforts method of accounting as prescribed by SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies is the preferred method. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 154 Accounting Changes and Error Corrections, financial information for prior periods has been restated to oil price volatility.reflect retrospective application of the successful efforts method. We are susceptiblebelieve the successful efforts method provides a more transparent representation of our results of operations and the ability to significant upward and downward revisions toassess our Proved Reserve volumes and values as a result of changesfuture investments in year end oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the corresponding adjustment to the projected economic life of such properties. Pricesbalance sheet date. The significant differences between successful efforts and full cost accounting for oil and gas are likelyproperties relate to continuethe expensing of exploration activities and related unsuccessful exploratory drilling activities. The expensing of these costs can create volatility in the statement of operations. The change in accounting principle resulted in a cumulative, non-cash increase to be volatile, resulting in future revisionretained earnings of $52.4 million, net of income tax, as of December 31, 2004. Retained earnings increased due to our Proved Reserve base. We perform a quarterly cost centerthe reversal of ceiling test of our oil and gas propertieswrite downs in prior years required under the full cost accounting rules of the SEC. These rules generally require that we price our future oilThere were no such impairments under the successful efforts accounting rules. The effect of the accounting change on income from continuing operations for the years ended December 31, 2006 and gas production at the oil2005 was a decrease of $4.9 million and gas prices$15.0 million, net of income tax, or $0.13 and $0.39 per diluted share, respectively. The decrease 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
28
Our current operations are in Venezuela.
28
29
For
2930
forms and 2) accumulated and communicated to our management, including our principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
None.
3031
and Corporate Governance
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 |
and Director Independence
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Page | ||||||||||
S-1 | ||||||||||
2006 | S-2 | |||||||||
S-3 | ||||||||||
S-4 | ||||||||||
S-5 | ||||||||||
S-7 | ||||||||||
2. | Consolidated Financial Statement Schedules and Other: | |||||||||
Qualifying Accounts | S-36 | |||||||||
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 | ||||||
4.1 | Form of Common Stock Certificate. | |||||
4.2 | Certificate of Designation, Rights and Preferences of the Series | |||||
4.3 | Third Amended and Restated Rights Agreement, dated as of | |||||
32
2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333-85900).) | ||||||
10.2 | ||||||
33
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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Form of Indemnification Agreement between Harvest Natural Resources, Inc. and | ||||||||
10.4 | Form of 2004 Long Term Stock Incentive Plan Stock Option | |||||||
10.5 | Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock | |||||||
10.6 | Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock | |||||||
10.7† | 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.) | |||||||
10.8† | 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.) | |||||||
10.9† | 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.) | |||||||
10.10† | 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.) | |||||||
10.11† | 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.) | |||||||
10.12† | 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.) | |||||||
10.13† | 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.) | |||||||
10.14 | 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].) | |||||||
10.15 | 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.) | |||||||
10.16 | 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.) | |||||||
10.17 | 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.) |
34
10.18† | 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.) | |||||
10.19† | 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.) | |||||
10.20 | 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. (Incorporated by reference to Exhibit 10.32 to our Form 10-K filed on March 13, 2007, File No. 1-10762.) | |||||
10.21 | Form of 2006 Long Term Incentive Plan Stock Option Agreement – Five Year Vesting, Seven Year Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-10762.) | |||||
10.22 | Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.) | |||||
10.23† | Employment Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) | |||||
10.24† | Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) | |||||
10.25† | Employee Restricted Stock Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) | |||||
10.26† | Consulting Agreement dated July 16, 2007 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) | |||||
10.27 | Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No. 1-10762.) | |||||
10.28† | Separation Agreement dated November 16, 2007 between Harvest Natural Resources, Inc. and Byron A. Dunn. | |||||
21.1 | List of subsidiaries. | |||||
23.1 | Consent of PricewaterhouseCoopers LLP | |||||
23.2 | Consent of | |||||
31.1 | ||||||
Certification |
35
32.1 | Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer. | |||||
32.2 | Certification | |||||
† | Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item |
(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
We have completed an integrated audit of Harvest Natural Resources, Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item 15 (a)(1)15(a)1 present fairly, in all material respects, the financial position of Harvest Natural Resources,Resource, Inc. and its subsidiaries at December 31, 20042007 and 2003,December 31, 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20042007 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 indexappearing under Item 15(a)(2)2 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. TheseAlso in our opinion, the Company maintained, in all material respects, effective internal control over financial statements and financial statement schedule arereporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Framework issued by the responsibilityCommittee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management. Our responsibilitymanagement is to express an opinion onresponsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated 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 auditaudits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An auditmisstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements includesincluded 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.
opinions.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reportingoil 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.
gas producing activities.
S-1
December 31, | ||||||||||||||||
2004 | 2003 | December 31, | ||||||||||||||
(in thousands, except per | 2007 | 2006* | ||||||||||||||
share data) | (in thousands, except per share data) | |||||||||||||||
ASSETS | ||||||||||||||||
Current Assets: | ||||||||||||||||
Cash and cash equivalents | $ | 84,600 | $ | 138,660 | $ | 120,841 | $ | 148,079 | ||||||||
Restricted cash | 12 | 12 | 6,769 | 15,888 | ||||||||||||
Accounts and notes receivable: | ||||||||||||||||
Accrued oil sales | 58,937 | 32,766 | ||||||||||||||
Joint interest and other, net | 12,780 | 11,197 | ||||||||||||||
Put options | 14,209 | — | ||||||||||||||
Accounts receivable, net | 9,418 | 9,811 | ||||||||||||||
Advances to equity affiliate | 16,352 | 19,146 | ||||||||||||||
Deferred income tax | 251 | — | — | 5,608 | ||||||||||||
Prepaid expenses and other | 1,426 | 805 | 1,032 | 1,246 | ||||||||||||
Total Current Assets | 172,215 | 183,440 | 154,412 | 199,778 | ||||||||||||
Restricted Cash | 16 | 16 | — | 73,001 | ||||||||||||
Other Assets | 2,072 | 2,080 | 4,301 | 176 | ||||||||||||
Deferred Income Taxes | 6,034 | 4,749 | ||||||||||||||
Investment in equity affiliates | 251,173 | 192,090 | ||||||||||||||
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 (successful efforts method) | 3,163 | 2,900 | ||||||||||||||
Other administrative property | 10,008 | 8,948 | 1,481 | 1,375 | ||||||||||||
641,090 | 602,570 | 4,644 | 4,275 | |||||||||||||
Accumulated depletion, depreciation, and amortization | (453,941 | ) | (418,507 | ) | ||||||||||||
Accumulated depletion, depreciation and amortization | (1,061 | ) | (955 | ) | ||||||||||||
Net Property and Equipment | 187,149 | 184,063 | 3,583 | 3,320 | ||||||||||||
$ | 367,486 | $ | 374,348 | $ | 413,469 | $ | 468,365 | |||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||
Current Liabilities: | ||||||||||||||||
Accounts payable, trade and other | $ | 8,428 | $ | 4,163 | $ | 5,949 | $ | 3,827 | ||||||||
Accounts payable, related party | 11,063 | 10,557 | 10,093 | 9,637 | ||||||||||||
Accrued expenses | 29,355 | 15,069 | 11,895 | 12,975 | ||||||||||||
Accrued interest payable | 71 | 1,427 | ||||||||||||||
Accrued interest | 5,136 | 6,850 | ||||||||||||||
Deferred revenue | — | 11,217 | ||||||||||||||
Income taxes payable | 22,475 | 8,647 | 503 | 34 | ||||||||||||
Current portion of long-term debt | 11,833 | 6,367 | 9,302 | 37,674 | ||||||||||||
Total Current Liabilities | 83,225 | 46,230 | 42,878 | 82,214 | ||||||||||||
Long-Term Debt | — | 96,833 | — | 66,977 | ||||||||||||
Asset Retirement Liability | 1,941 | 1,459 | ||||||||||||||
Commitments and Contingencies | — | — | — | — | ||||||||||||
Minority Interest | 39,131 | 30,113 | 56,825 | 37,765 | ||||||||||||
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, 2007 and 2006; issued 38,513 shares and 37,974 shares at December 31, 2007 and 2006, respectively | 385 | 380 | ||||||||||||||
Additional paid-in capital | 185,183 | 175,051 | 201,938 | 194,176 | ||||||||||||
Retained earnings | 61,897 | 27,537 | 147,934 | 90,697 | ||||||||||||
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, 3,719 shares at December 31, 2007 and 770 shares at December 31, 2006, respectively | (36,491 | ) | (3,844 | ) | ||||||||||||
Total Stockholders’ Equity | 243,189 | 199,713 | 313,766 | 281,409 | ||||||||||||
$ | 367,486 | $ | 374,348 | $ | 413,469 | $ | 468,365 | |||||||||
* | Financial information for 2006 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle. |
S-2
Years Ended December 31, | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(in thousands, except per share data) | ||||||||||||
Revenues | ||||||||||||
Oil sales | $ | 154,075 | $ | 103,920 | $ | 127,015 | ||||||
Gas sales | 31,991 | 2,740 | — | |||||||||
Ineffective hedge activity | — | (565 | ) | (284 | ) | |||||||
186,066 | 106,095 | 126,731 | ||||||||||
Expenses | ||||||||||||
Operating expenses | 33,324 | 30,893 | 33,950 | |||||||||
Depletion, depreciation and amortization | 36,020 | 21,188 | 26,363 | |||||||||
Write-downs of oil and gas properties and impairments | — | 165 | 14,537 | |||||||||
General and administrative | 21,857 | 15,746 | 16,504 | |||||||||
Arbitration settlement | — | 1,477 | — | |||||||||
Bad debt recovery | (598 | ) | (374 | ) | (3,276 | ) | ||||||
Gain on sale of long-lived asset | (578 | ) | — | — | ||||||||
Taxes other than on income | 5,561 | 3,373 | 4,068 | |||||||||
95,586 | 72,468 | 92,146 | ||||||||||
Income from Operations | 90,480 | 33,627 | 34,585 | |||||||||
Other Non-Operating Income (Expense) | ||||||||||||
Gain on disposition of investment | — | 46,619 | 144,029 | |||||||||
Gain (loss) on early extinguishment of debt | (2,928 | ) | — | 874 | ||||||||
Investment earnings and other | 2,085 | 1,418 | 2,080 | |||||||||
Interest expense | (7,749 | ) | (10,405 | ) | (16,310 | ) | ||||||
Net gain (loss) on exchange rates | (622 | ) | 529 | 4,553 | ||||||||
(9,214 | ) | 38,161 | 135,226 | |||||||||
Income from Consolidated Companies Before Income Taxes and Minority Interest | 81,266 | 71,788 | 169,811 | |||||||||
Income Tax Expense | 33,288 | 9,657 | 60,295 | |||||||||
Income Before Minority Interest | 47,978 | 62,131 | 109,516 | |||||||||
Minority Interest in Consolidated Subsidiary Companies | 13,618 | 5,968 | 9,319 | |||||||||
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 Per Common Share: | ||||||||||||
Basic | $ | 0.95 | $ | 0.77 | $ | 2.90 | ||||||
Diluted | $ | 0.90 | $ | 0.74 | $ | 2.78 | ||||||
Other comprehensive loss: | ||||||||||||
Unrealized mark to market loss from cash flow hedging activities, net of tax | (487 | ) | — | — | ||||||||
Comprehensive income | $ | 33,873 | $ | 27,303 | $ | 100,362 | ||||||
Years Ended December 31, | ||||||||||||
2007 | 2006* | 2005* | ||||||||||
(in thousands, except per share data) | ||||||||||||
Revenues | ||||||||||||
Oil sales (a) | $ | 11,217 | $ | 54,858 | $ | 210,493 | ||||||
Gas sales | — | 4,648 | 26,448 | |||||||||
11,217 | 59,506 | 236,941 | ||||||||||
Expenses | ||||||||||||
Operating expenses | — | 9,241 | 39,723 | |||||||||
Depletion, depreciation and amortization | 384 | 15,435 | 58,922 | |||||||||
Exploration expense | 204 | — | — | |||||||||
General and administrative | 29,742 | 26,421 | 22,819 | |||||||||
Contribution to Science and Technology Fund | — | 3,887 | — | |||||||||
Account receivable write-off on retroactive oil price adjustments | — | — | 4,548 | |||||||||
Taxes other than on income | 423 | 3,948 | 6,358 | |||||||||
30,753 | 58,932 | 132,370 | ||||||||||
Income (Loss) from Operations | (19,536 | ) | 574 | 104,571 | ||||||||
Other Non-Operating Income (Expense) | ||||||||||||
Gain on Financing Transactions | 49,623 | — | — | |||||||||
Investment earnings and other | 9,065 | 9,406 | 4,205 | |||||||||
Interest expense | (8,224 | ) | (23,156 | ) | (3,388 | ) | ||||||
Net gain (loss) on exchange rates | (14 | ) | (121 | ) | 2,752 | |||||||
50,450 | (13,871 | ) | 3,569 | |||||||||
Income (Loss) from Consolidated Companies Before Income Taxes and Minority Interest | 30,914 | (13,297 | ) | 108,140 | ||||||||
Income Tax Expense | 6,312 | 60,917 | 57,025 | |||||||||
Income (Loss) Before Minority Interest | 24,602 | (74,214 | ) | 51,115 | ||||||||
Minority Interest in Consolidated Subsidiary Companies | 19,060 | (11,712 | ) | 12,239 | ||||||||
Income (loss) from Consolidated Companies | 5,542 | (62,502 | ) | 38,876 | ||||||||
Net Income from Unconsolidated Equity Affiliates | 51,695 | — | — | |||||||||
Net Income (Loss) | $ | 57,237 | $ | (62,502 | ) | $ | 38,876 | |||||
Net Income (Loss) Per Common Share: | ||||||||||||
Basic | $ | 1.57 | $ | (1.68 | ) | $ | 1.05 | |||||
Diluted | $ | 1.51 | $ | (1.68 | ) | $ | 1.01 | |||||
(a) | Recognition of deferred revenue – See Note 1 – Organization and Summary of Significant Accounting Policies – Revenue Recognition. | |
* | Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle. |
S-3
Retained | Accumulated | |||||||||||||||||||||||||||
Common | Additional | Earnings | Other | |||||||||||||||||||||||||
Shares | Common | Paid-in | (Accumulated | Comprehensive | Treasury | |||||||||||||||||||||||
Issued | Stock | Capital | Deficit) | 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 | ||||||||||||||||||||
Issuance of common shares: | ||||||||||||||||||||||||||||
Exercise of warrants | 53 | — | 600 | — | — | — | 600 | |||||||||||||||||||||
Exercise of stock options | 1,001 | 10 | 7,381 | — | — | — | 7,391 | |||||||||||||||||||||
Employee stock-based compensation | 85 | 1 | 2,151 | — | — | — | 2,152 | |||||||||||||||||||||
Treasury stock (34 shares) | — | — | — | — | — | (540 | ) | (540 | ) | |||||||||||||||||||
Accumulated other comprehensive loss | — | — | — | — | (487 | ) | — | (487 | ) | |||||||||||||||||||
Net Income | — | — | — | 34,360 | — | — | 34,360 | |||||||||||||||||||||
Balance at December 31, 2004 | 37,544 | $ | 375 | $ | 185,183 | $ | 61,897 | $ | (487 | ) | $ | (3,779 | ) | $ | 243,189 | |||||||||||||
Accumulated | ||||||||||||||||||||||||||||
Common | Additional | Other | ||||||||||||||||||||||||||
Shares | Common | Paid-in | Retained | Comprehensive | Treasury | |||||||||||||||||||||||
Issued | Stock | Capital | Earnings | Gain(Loss) | Stock | Total | ||||||||||||||||||||||
Balance at January 1, 2005 | 37,544 | $ | 375 | $ | 185,183 | $ | 114,323 | $ | (487 | ) | $ | (3,779 | ) | $ | 295,615 | |||||||||||||
Issuance of common shares: | ||||||||||||||||||||||||||||
Exercise of stock options | 139 | 3 | 829 | — | — | — | 832 | |||||||||||||||||||||
Employee stock-based compensation | 74 | — | 2,230 | — | — | — | 2,230 | |||||||||||||||||||||
Purchase of Treasury Shares | — | — | — | — | — | (65 | ) | (65 | ) | |||||||||||||||||||
Accumulated other comprehensive gain | — | — | — | — | 487 | — | 487 | |||||||||||||||||||||
Net Income* | — | — | — | 38,876 | — | — | 38,876 | |||||||||||||||||||||
Balance at December 31, 2005 | 37,757 | 378 | 188,242 | 153,199 | — | (3,844 | ) | 337,975 | ||||||||||||||||||||
Issuance of common shares: | ||||||||||||||||||||||||||||
Exercise of stock options | 137 | 1 | 879 | — | — | — | 880 | |||||||||||||||||||||
Employee stock-based compensation | 80 | 1 | 5,055 | — | — | — | 5,056 | |||||||||||||||||||||
Net Loss * | — | — | — | (62,502 | ) | — | — | (62,502 | ) | |||||||||||||||||||
Balance at December 31, 2006 | 37,974 | 380 | 194,176 | 90,697 | — | (3,844 | ) | 281,409 | ||||||||||||||||||||
Issuance of common shares: | ||||||||||||||||||||||||||||
Exercise of stock options | 402 | 4 | 1,934 | — | — | — | 1,938 | |||||||||||||||||||||
Employee stock-based compensation | 137 | 1 | 5,828 | — | — | — | 5,829 | |||||||||||||||||||||
Purchase of Treasury Shares | — | — | — | — | — | (32,647 | ) | (32,647 | ) | |||||||||||||||||||
Net Income | — | — | — | 57,237 | — | — | 57,237 | |||||||||||||||||||||
Balance at December 31, 2007 | 38,513 | $ | 385 | $ | 201,938 | $ | 147,934 | $ | — | $ | (36,491 | ) | $ | 313,766 | ||||||||||||||
* | Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle. |
S-4
Years Ended December 31, | Years Ended December 31, | |||||||||||||||||||||||
2004 | 2003 | 2002 | 2007 | 2006* | 2005* | |||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Cash Flows From Operating Activities: | ||||||||||||||||||||||||
Net income | $ | 34,360 | $ | 27,303 | $ | 100,362 | ||||||||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||||||||||
Net income (loss) | $ | 57,237 | $ | (62,502 | ) | $ | 38,876 | |||||||||||||||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depletion, depreciation and amortization | 36,020 | 21,188 | 26,363 | 384 | 15,435 | 58,922 | ||||||||||||||||||
Write-down of oil and gas properties and impairment | — | 165 | 14,537 | |||||||||||||||||||||
Amortization of financing costs | 228 | 497 | 1,745 | |||||||||||||||||||||
Gain on disposition of assets and investments | (578 | ) | (46,619 | ) | (144,029 | ) | ||||||||||||||||||
Write off of unamortized financing costs | 936 | — | — | |||||||||||||||||||||
Equity in net earnings (losses) of affiliated companies | — | 28,860 | (165 | ) | ||||||||||||||||||||
Allowance for employee notes and accounts receivable | (598 | ) | (169 | ) | (2,987 | ) | ||||||||||||||||||
Exploration expense | 204 | — | — | |||||||||||||||||||||
Gain on financing transactions | (49,623 | ) | — | — | ||||||||||||||||||||
Net income from unconsolidated equity affiliates | (51,695 | ) | — | — | ||||||||||||||||||||
Account receivable write-off on retroactive oil price adjustments | — | — | 4,548 | |||||||||||||||||||||
Deferred compensation expense | 1,521 | 306 | — | — | — | (745 | ) | |||||||||||||||||
Non-cash compensation related charges | 2,152 | 296 | 1,458 | 6,108 | 5,056 | 2,230 | ||||||||||||||||||
Minority interest in consolidated subsidiary companies | 13,618 | 5,968 | 9,319 | 19,060 | (11,712 | ) | 12,239 | |||||||||||||||||
Gain from early extinguishment of debt | — | — | (874 | ) | ||||||||||||||||||||
Deferred income taxes | (1,285 | ) | (667 | ) | 53,618 | 5,608 | (2,556 | ) | 2,982 | |||||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||||||||||
Accounts and notes receivable | (27,156 | ) | (7,935 | ) | (1,972 | ) | 393 | 61,839 | (4,481 | ) | ||||||||||||||
Advances to equity affiliate | 2,794 | (19,146 | ) | — | ||||||||||||||||||||
Prepaid expenses and other | (621 | ) | 2,164 | (1,130 | ) | 214 | 903 | (723 | ) | |||||||||||||||
Commodity hedging contract | (14,947 | ) | (430 | ) | 430 | — | — | 14,947 | ||||||||||||||||
Accounts payable | 4,265 | 359 | (4,328 | ) | 2,122 | 3,419 | (8,020 | ) | ||||||||||||||||
Accounts payable, related party | 506 | 4,386 | (604 | ) | 456 | 434 | (1,860 | ) | ||||||||||||||||
Accrued interest payable | (1,356 | ) | 22 | (2,489 | ) | |||||||||||||||||||
Accrued expenses | 12,765 | (382 | ) | (9,686 | ) | (1,251 | ) | (5,469 | ) | (10,165 | ) | |||||||||||||
Accrued interest | (1,714 | ) | 4,213 | 2,565 | ||||||||||||||||||||
Deferred revenue | (11,217 | ) | 4,489 | 6,728 | ||||||||||||||||||||
Asset retirement liability | 482 | 1,459 | — | — | 24 | 188 | ||||||||||||||||||
Income taxes payable | 13,828 | 1,767 | 3,059 | 469 | (18,875 | ) | (3,566 | ) | ||||||||||||||||
Net Cash Provided by Operating Activities | 74,140 | 38,538 | 42,627 | |||||||||||||||||||||
Net Cash Provided By (Used In) Operating Activities | (20,451 | ) | (24,448 | ) | 114,665 | |||||||||||||||||||
Cash Flows from Investing Activities: | ||||||||||||||||||||||||
Proceeds from sale of investment | — | 69,500 | 189,841 | |||||||||||||||||||||
Proceeds from sale of long-lived assets | 578 | — | — | |||||||||||||||||||||
Additions of property and equipment | (39,106 | ) | (60,925 | ) | (43,346 | ) | (851 | ) | (1,657 | ) | (16,147 | ) | ||||||||||||
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 equity affiliates | (7,388 | ) | (513 | ) | — | |||||||||||||||||||
(Increase) decrease in restricted cash | 82,120 | (88,889 | ) | 28 | ||||||||||||||||||||
Investment costs | (1,156 | ) | (1,900 | ) | (349 | ) | (4,125 | ) | 503 | 472 | ||||||||||||||
Net Cash Provided by (Used In) Investing Activities | (39,684 | ) | 38,191 | 126,143 | ||||||||||||||||||||
Net Cash Provided By (Used In) Investing Activities | 69,756 | (90,556 | ) | (15,647 | ) | |||||||||||||||||||
Cash Flows from Financing Activities: | ||||||||||||||||||||||||
Net proceeds from issuances of common stock | 7,451 | 1,201 | 3,345 | 1,938 | 880 | 767 | ||||||||||||||||||
Purchase of treasury stock | — | (404 | ) | — | (32,755 | ) | — | — | ||||||||||||||||
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 | (45,726 | ) | (19,769 | ) | (6,366 | ) | ||||||||||||||||||
Dividend paid to minority interest | — | — | (15,000 | ) | ||||||||||||||||||||
Net Cash Used In Financing Activities | (88,516 | ) | (2,570 | ) | (113,293 | ) | ||||||||||||||||||
Net Cash Provided By (Used In) Financing Activities | (76,543 | ) | 100,064 | (20,599 | ) | |||||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (54,060 | ) | 74,159 | 55,477 | (27,238 | ) | (14,940 | ) | 78,419 | |||||||||||||||
Cash and Cash Equivalents at Beginning of Year | 138,660 | 64,501 | 9,024 | 148,079 | 163,019 | 84,600 | ||||||||||||||||||
Cash and Cash Equivalents at End of Year | $ | 84,600 | $ | 138,660 | $ | 64,501 | $ | 120,841 | $ | 148,079 | $ | 163,019 | ||||||||||||
Supplemental Disclosures of Cash Flow Information: | ||||||||||||||||||||||||
Cash paid during the year for interest expense | $ | 12,541 | $ | 13,241 | $ | 19,201 | $ | 7,972 | $ | 23,171 | $ | 795 | ||||||||||||
Cash paid during the year for income taxes | $ | 11,705 | $ | 4,254 | $ | 3,935 | $ | 201 | $ | 62,505 | $ | 20,991 | ||||||||||||
* | Financial information for 2006 and 2005 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Organization and Summary of Significant Accounting Policies – Property and Equipment and Change in Accounting Principle. |
S-5
$1.0 million.
S-6
bylaws.
decreased by dividends paid and amortization of basis differential. No dividends were declared or paid by Fusion or Petrodelta in 2007.
S-7
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. With the formation of Petrodelta, Harvest Vinccler recognized deferred revenue of $11.2 million for 2005 and first quarter 2006 deliveries that had been deferred pending clarification on the calculation of crude prices under the Transitory Agreement.
At December 31, 2007, Harvest Vinccler had 4.7 billion Venezuela Bolivars (“Bolivars”) which are shown in the December 31, 2007 financial statements as $2.4 million in cash and cash equivalents.
Marketable Securities
Marketable securities are carried at cost. Cash Equivalents may be comprised of high-grade debt instruments, demand or time deposits, certificates of depositagreement. SeeNote 2 — Long-Term Debt and commercial paper of highly rated U.S. corporations, all having maturities of no more than 180 days.
S-7
Credit Risk and Operations
dividend.
S-8
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.
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.2005.
We continue to assess production levels There was no difference between net income and commodity prices in conjunction with our capital resources and liquidity requirements.
Asset Retirement Liability
Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accountingcomprehensive net income 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 of
S-8
certain wells in Venezuela. SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. Nine wells were abandoned in the year ended December 31, 2004 and 11 wells were abandoned in year ended2005. All hedging instruments expired under their own terms on December 31, 2003. Changes in asset retirement obligations during the years ended December 31, 2004 and 2003 were as follows:2005.
December 31, | December, 31 | |||||||
2004 | 2003 | |||||||
Asset retirement obligations beginning of period | $ | 1,459 | $ | — | ||||
Liabilities recorded during the period | 1,454 | 4,237 | ||||||
Liabilities settled during the period | (540 | ) | (733 | ) | ||||
Revisions in estimated cash flows | (470 | ) | (2,125 | ) | ||||
Accretion expense | 38 | 80 | ||||||
Asset retirement obligations end of period | $ | 1,941 | $ | 1,459 | ||||
Accounts and Notes Receivable
million.
We follow
successful efforts accounting rules. 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, 2004 consisted of property acquisition costs in the amount of $2.9 million which were all incurred prior to 2001. Alleffect of the excluded costs at December 31, 2004 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 basedaccounting change on the total proved reserves of the country cost center. Depletion expense, which was substantially all attributable to the Venezuelan cost centerincome from continuing operations for the years ended December 31, 2004, 20032006 and 20022005 was $34.1 million, $19.6a decrease of $4.9 million and $24.9$15.0 million, ($2.56, $2.52net of income tax, or $0.13 and $2.56$0.39 per equivalent barrel),diluted share, respectively.
A gain The decrease in income from continuing operations was due to an increase in depletion expense. There was no effect on cash and cash equivalents.
S-9
The major components of property and equipment at December 31 are as follows (in thousands):
2004 | 2003 | |||||||
Proved property costs | $ | 621,679 | $ | 582,456 | ||||
Costs excluded from amortization | 2,900 | 2,900 | ||||||
Oilfield inventories | 6,503 | 8,266 | ||||||
Other administrative property | 10,008 | 8,948 | ||||||
641,090 | 602,570 | |||||||
Accumulated depletion, impairment and depreciation | (453,941 | ) | (418,507 | ) | ||||
$ | 187,149 | $ | 184,063 | |||||
We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the SEC. The consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downs in 2004 or 2003. Equity in Net Losses of Affiliated Companies includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ending September 30, 2003.
Stock-Based Compensation
S-10
2004 | 2003 | 2002 | ||||||||||
Net income, as reported | $ | 34,360 | $ | 27,303 | $ | 100,362 | ||||||
Add: Stock-based employee compensation cost, net of tax | 999 | 296 | 915 | |||||||||
Less: Total stock-based employee compensation cost determined under fair value based method, net of tax | (1,382 | ) | (1,056 | ) | (2,905 | ) | ||||||
Net income – proforma | $ | 33,977 | $ | 26,543 | $ | 98,372 | ||||||
Net income per common share: | ||||||||||||
Basic – as reported | $ | 0.95 | $ | 0.77 | $ | 2.90 | ||||||
Basic – proforma | $ | 0.94 | $ | 0.75 | $ | 2.87 | ||||||
Diluted – as reported | $ | 0.90 | $ | 0.74 | $ | 2.78 | ||||||
Diluted – proforma | $ | 0.89 | $ | 0.72 | $ | 2.75 | ||||||
2005 | ||||
(in thousands, except per share data) | ||||
Net income, as reported | $ | 38,876 | ||
Add: Stock-based employee compensation cost, net of tax | 2,635 | |||
Less: Total stock-based employee compensation cost determined under fair value based method, net of tax | (2,711 | ) | ||
Net income — proforma | $ | 38,800 | ||
Net income per common share: | ||||
Basic — as reported | $ | 1.05 | ||
Basic — proforma | $ | 1.05 | ||
Diluted — as reported | $ | 1.01 | ||
Diluted — proforma | $ | 1.01 | ||
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Income Taxes
With the formation of Petrodelta, Harvest Vinccler recognized the deferred tax related to the deferred revenue discussed above.
We have significant
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.
Comprehensive Income
Statement of Financial Accounting Standards No. 130 (“SFAS 130”) requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. We reflected unrealized 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.
S-11
S-11
In December 2004,February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2 — Effective Date of FASB Statement of Financial Accounting Standard 153 Exchanges of Nonmonetary AssetsNo. 157 (“SFAS 153”FSP 157-2”), an amendmentwhich delays the effective date of Accounting Principles Board (“APB”) Opinion No. 29 (“Opinion 29”). SFAS 153 amends Opinion 29 to eliminate the exception157 for nonmonetary exchanges of similar productiveall nonfinancial assets and replaces it withnonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a general exception for exchanges of nonmonetary assets that dorecurring basis (at least annually), until January 1, 2009. FSP 157-2 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.
S-12
operations or cash flows.
Reclassifications
Certain items in 2002 and 2003 have been reclassified to conform to the 2004 financial statement presentation.
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, | |||||||
2007 | 2006 | |||||||
Note payable with interest at 10.0% | $ | — | $ | 55,814 | ||||
Note payable with interest at 10.0% | — | 39,535 | ||||||
Note payable with interest at 12.5% | 9,302 | 9,302 | ||||||
9,302 | 104,651 | |||||||
Less current portion | 9,302 | 37,674 | ||||||
$ | — | $ | 66,977 | |||||
In
S-12S-13
of $1.3 million
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 4.4 billion Venezuelan Bolivars (“Bolivars”) (approximately $6.3 million)Note 4 — Taxes. 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. The interest rate for this loan is 90-day LIBOR plus 6 percentage points. The term is four years with a quarterly amortization of $1.3 million beginning with the first quarter 2004 to coincide with the first payment from our gas sales.
We have classified all of our outstanding debt as current at December 31, 2004.
2008.
month.
• | Three claims were filed in July 2004 and allege a failure to withhold for technical service payments and a failure to pay taxes on the capital fee reimbursement and related interest paid by PDVSA under the OSA. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss one of the claims and has protested with the municipality the remaining claims. | ||
• | Two claims were filed in July 2006 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on these claims. | ||
• | Two claims were filed in August 2006 alleging a failure to pay taxes on estimated revenues for the second quarter of 2006 and a withholding error with respect to certain vendor payments. Harvest Vinccler has filed a protest with the Tax Court in Barcelona, Venezuela, on one claim and filed a protest with the municipality on the other claim. | ||
• | Two claims were filed in March 2007 alleging a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a protest with the municipality on these claims. |
S-13S-14
• | One claim was filed in April 2005 alleging the failure to pay taxes at a new rate set by the Municipality. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claim. | ||
• | Two claims were filed in June 2007. One claim relates to the period 2003 through 2006 and seeks to impose a tax on interest paid by PDVSA under the OSA. The second claim alleges a failure to pay taxes on estimated revenues for the third and fourth quarters of 2006. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims. | ||
• | Two claims were filed in July 2007 seeking to impose penalties on tax assessments filed and settled in 2004. Harvest Vinccler has filed a motion with the Tax Court in Barcelona, Venezuela, to enjoin and dismiss the claims. |
2004 | 2003 | 2002 | 2007 | 2006 | 2005 | |||||||||||||||||||
Venezuelan municipal taxes | $ | 4,485 | $ | 2,741 | $ | 3,805 | $ | — | $ | 3,191 | $ | 5,788 | ||||||||||||
Franchise taxes | 464 | 341 | 139 | 166 | 175 | (70 | ) | |||||||||||||||||
Payroll and other taxes | 612 | 291 | 124 | 257 | 582 | 640 | ||||||||||||||||||
$ | 5,561 | $ | 3,373 | $ | 4,068 | $ | 423 | $ | 3,948 | $ | 6,358 | |||||||||||||
S-15
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 | ||||
2006 | ||||
Deferred tax assets: | ||||
Operating loss carryforwards | $ | 7,466 | ||
Difference in basis of assets | 25,343 | |||
Deferred revenue | 5,608 | |||
Valuation allowance | (32,809 | ) | ||
Net deferred tax asset | 5,608 | |||
Less current portion | 5,608 | |||
$ | — | |||
2004 | 2003 | 2002 | 2007 | 2006 | 2005 | |||||||||||||||||||
Income (loss) before income taxes | ||||||||||||||||||||||||
United States | $ | (16,593 | ) | $ | 34,236 | $ | 92,394 | $ | (17,786 | ) | $ | (15,688 | ) | $ | 8,178 | |||||||||
Foreign | 97,859 | 37,552 | 77,417 | 48,700 | 2,391 | 99,962 | ||||||||||||||||||
Total | $ | 81,266 | $ | 71,788 | $ | 169,811 | $ | 30,914 | $ | (13,297 | ) | $ | 108,140 | |||||||||||
2004 | 2003 | 2002 | 2007 | 2006 | 2005 | |||||||||||||||||||
Current: | ||||||||||||||||||||||||
United States | $ | (8 | ) | $ | 1,187 | $ | 351 | $ | 400 | $ | — | $ | 739 | |||||||||||
Foreign | 34,581 | 9,137 | 6,326 | 5,912 | 63,473 | 53,304 | ||||||||||||||||||
$ | 34,573 | $ | 10,324 | $ | 6,677 | 6,312 | 63,473 | 54,043 | ||||||||||||||||
Deferred: | ||||||||||||||||||||||||
United States | $ | — | $ | — | $ | 53,413 | ||||||||||||||||||
Foreign | (1,285 | ) | (667 | ) | 205 | — | (2,556 | ) | 2,982 | |||||||||||||||
(1,285 | ) | (667 | ) | 53,618 | $ | 6,312 | $ | 60,917 | $ | 57,025 | ||||||||||||||
$ | 33,288 | $ | 9,657 | $ | 60,295 | |||||||||||||||||||
S-14S-16
2004 | 2003 | 2002 | ||||||||||
Computed tax expense at the statutory rate | $ | 28,443 | $ | 15,025 | $ | 59,348 | ||||||
State income taxes | 25 | 1,188 | 353 | |||||||||
Effect of foreign source income and rate differentials on foreign income | (2,169 | ) | (15,849 | ) | (19,373 | ) | ||||||
Change in valuation allowance | 7,020 | 9,219 | 19,446 | |||||||||
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 | |||||||||
Total income tax expense | $ | 33,288 | $ | 9,657 | $ | 60,295 | ||||||
2007 | 2006 | 2005 | ||||||||||
Computed tax expense (benefit) at the statutory rate | $ | 10,820 | $ | (2,930 | ) | $ | 43,083 | |||||
Effect of foreign source income and rate differentials on foreign income | (11,140 | ) | 8,563 | 16,065 | ||||||||
Change in valuation allowance | 1,085 | 5,446 | 13,129 | |||||||||
Alternative minimum tax | — | — | 739 | |||||||||
Deemed income inclusion | 12,942 | — | — | |||||||||
Venezuela tax settlement | — | 49,793 | — | |||||||||
Net operating loss utilization | (7,306 | ) | — | (15,567 | ) | |||||||
Other | (89 | ) | 45 | (424 | ) | |||||||
Total income tax expense | $ | 6,312 | $ | 60,917 | $ | 57,025 | ||||||
At December 31, 2004, we had, for federal income tax purposes operating loss carryforwards of approximately $42.1 million, expiring in the years 2014 through 2025.
were fully utilized at December 31, 2007.
S-17
In January 2001, we adopted the Non-Employee Director Stock Purchase Plan (the “Stock Purchase Plan”) to encourage our directors to acquire a greater proprietary interest in us through the ownership of our common stock. Under the Stock Purchase Plan, each non-employee director could elect to receive shares of our common stock for all or a portion of their fee for serving as a director. The number of shares issuable is equal to 1.5 times the amount of cash compensation due the director divided by the fair market value of the common stock on the scheduled date of payment of the applicable director’s fee. The shares have a restriction upon their sale for one year from the date of issuance. As of December 31, 2002, 337,850 shares had been issued from the plan. The Stock Purchase Plan was terminated by the Board of Directors in September 2002.
S-15
changes in capitalization, such as stock splits. In the event of a change in control, all outstanding options become immediately exercisable to the extent permitted by the plan. All options granted to date vest ratably over a three-year period from their dates of grant and expire ten years from grant date.
2004 | 2003 | 2002 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||||||||||||||||||||
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 | $ | 7.70 | 4,123 | $ | 8.61 | 4,070 | $ | 8.18 | 3,793 | ||||||||||||||||||||||||||||||
Options granted | 13.36 | 378 | 6.26 | 246 | 4.84 | 165 | 9.63 | 866 | 10.62 | 558 | 11.51 | 922 | ||||||||||||||||||||||||||||||||||||
Options exercised | (7.41 | ) | (955 | ) | 2.32 | (494 | ) | 2.21 | (1,515 | ) | (4.73 | ) | (397 | ) | (5.69 | ) | (65 | ) | (3.45 | ) | (241 | ) | ||||||||||||||||||||||||||
Options cancelled | (6.31 | ) | (153 | ) | 11.37 | (452 | ) | 8.03 | (292 | ) | (13.49 | ) | (420 | ) | (19.96 | ) | (440 | ) | (14.24 | ) | (404 | ) | ||||||||||||||||||||||||||
Outstanding at end of the year | 8.18 | 3,793 | 7.52 | 4,523 | 7.42 | 5,223 | 7.80 | 4,172 | 7.70 | 4,123 | 8.61 | 4,070 | ||||||||||||||||||||||||||||||||||||
Exercisable at end of the year | 7.71 | 3,236 | 8.18 | 3,857 | 8.49 | 4,360 | 5.87 | 2,372 | 5.91 | 2,719 | 7.40 | 2,886 | ||||||||||||||||||||||||||||||||||||
S-18
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 12/31/07 | Life | Price | Value | at 12/31/07 | Price | Value | |||||||||||||||||||||
$ 1.55 - $ 2.75 | 1,295 | 2.29 | $ | 2.02 | $ | 13,576 | 1,295 | $ | 2.02 | $ | 13,576 | |||||||||||||||||
$ 4.86 - $ 7.10 | 226 | 4.78 | 5.82 | 1,509 | 226 | 5.82 | 1,509 | |||||||||||||||||||||
$ 8.72 - $ 10.91 | 1,906 | 7.40 | 9.90 | 4,958 | 300 | 9.32 | 954 | |||||||||||||||||||||
$12.50 - $ 13.90 | 745 | 6.89 | 13.09 | — | 551 | 13.06 | — | |||||||||||||||||||||
4,172 | $ | 20,043 | 2,372 | $ | 16,039 | |||||||||||||||||||||||
2007 | 2006 | 2005 | ||||||||||
Weighted average fair value | $ | 4.67 | $ | 5.98 | $ | 6.35 | ||||||
Weighted averaged expected life | 7 | 7 | 7 | |||||||||
Valuation assumptions: | ||||||||||||
Expected volatility | 47.7-48.7 | % | 49.9%-53.3 | % | 50.0%-53.4 | % | ||||||
Risk-free interest rate | 4.5%-4.6 | % | 4.6%-5.2 | % | 3.9%-4.6 | % | ||||||
Expected dividend yield | 0 | % | 0 | % | 0 | % | ||||||
Expected annual forfeitures | 3 | % | 3 | % | 3 | % |
Weighted-Average | ||||||||
Grant-Date | ||||||||
Nonvested Shares | Shares | Fair Value | ||||||
Nonvested at January 1, 2007 | 1,404 | $ | 6.75 | |||||
Granted | 916 | 4.67 | ||||||
Vested | (420 | ) | (7.48 | ) | ||||
Forfeited | (50 | ) | (9.63 | ) | ||||
Nonvested at December 31, 2007 | 1,850 | $ | 5.83 | |||||
S-19
2005 was $4.5 million, $4.1 million and $2.7 million, respectively.
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 |
S-16
Note 7 — 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 | |||||
2007 | 2006 | 2005 | ||||||||||
(in thousands) | ||||||||||||
Segment Revenues | ||||||||||||
Oil and gas sales: | ||||||||||||
Venezuela | $ | 11,217 | $ | 59,506 | $ | 236,941 | ||||||
Total oil and gas sales | 11,217 | 59,506 | 236,941 | |||||||||
Segment Income (Loss) | ||||||||||||
Venezuela | 76,276 | (46,835 | ) | 52,133 | ||||||||
United States and other | (19,039 | ) | (15,667 | ) | (13,257 | ) | ||||||
Net income (loss) | $ | 57,237 | $ | (62,502 | ) | $ | 38,876 | |||||
S-17
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(in thousands) | ||||||||
Operating Segment Assets | ||||||||
Venezuela | $ | 303,042 | $ | 351,943 | ||||
United States and other | 126,766 | 155,973 | ||||||
429,808 | 507,916 | |||||||
Intersegment eliminations | (16,339 | ) | (39,551 | ) | ||||
$ | 413,469 | $ | 468,365 | |||||
Note 87 — RussianVenezuela Operations
Geoilbent
— Petrodelta S.A.
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, for the year ended December 31, 2001 was 39 percent. We recorded as our share in the losses of Arctic Gas $1.5 million for the period ended April 12, 2002. Summarized financial information for Arctic Gas follows (in thousands). All amounts represent 100 percent of Arctic Gas.
S-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 Petrodelta has adopted 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 HNR Finance. Petrodelta has hired personnel, largely from Harvest Vinccler; and the Board of Directors of Petrodelta has appointed the management of Petrodelta. Certain of these appointments are made by the shareholders. Effective August 9, — Venezuela2007, Mr. Karl L. Nesselrode, Vice President, Engineering and Business Development of Harvest, accepted a long-term secondment to Petrodelta as its Operations
On July 31, 1992, we and Technical Manager. Per Petrodelta’s bylaws, the Operations and Technical Manager’s position is designated as our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), signedappointment. Mr. Nesselrode will remain an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then oneofficer of three exploration and production affiliatesHarvest. The General Manager of Petrodelta (CVP appointment) has been appointed by the Board of Directors of Petrodelta. This position is in charge of the national oil company, PDVSA. The operating service agreement coversdaily management of the Uracoa, Bombalbusiness of Petrodelta and Tucupita Fields that comprisehas the South Monagas Unit.power and duties customary to manage, direct and supervise the accounting of Petrodelta.
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 atDollars.
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.
Note 10 — United States Operations
We acquired a 10040 percent interest in three California State offshore oilPetrodelta and gas leases (“California Leases”) and a parcelhas recorded its share of onshore propertythe earnings of Petrodelta 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 responsibleApril 1, 2006 to December 31, 2007 in the State of California for any remediation costs associatedcurrent year in accordance with the onshore propertyConversion Contact. Summary historical financial information has been presented below at December 31, 2006 and 2007 and for the nine months ended December 31, 2006 and the related offshore oil and gas leases.
S-19S-21
Year Ended | Nine Months Ended | |||||||
December 31, 2007 | December 31, 2006 | |||||||
Barrels of oil sold | 5,374 | 5,211 | ||||||
MCF of gas sold | 13,456 | 11,519 | ||||||
Total BOE | 7,616 | 7,131 | ||||||
Average price per barrel | $ | 58.61 | $ | 50.98 | ||||
Average price per mcf | $ | 1.54 | $ | 1.54 | ||||
Revenues: | ||||||||
Oil sales | $ | 314,928 | $ | 265,625 | ||||
Gas sales | 20,789 | 17,796 | ||||||
Royalty | (114,847 | ) | (96,790 | ) | ||||
220,870 | 186,631 | |||||||
Expenses : | ||||||||
Operating expenses | 23,752 | 22,729 | ||||||
Depletion, depreciation and amortization | 18,549 | 17,076 | ||||||
General and administrative | 19,880 | 11,093 | ||||||
Taxes other than on income | 2,747 | 2,029 | ||||||
64,928 | 52,927 | |||||||
Income from operations and before income taxes | 155,942 | 133,704 | ||||||
Current income tax expense | 85,849 | 67,188 | ||||||
Deferred income tax benefit | (21,348 | ) | (23,415 | ) | ||||
Net Income | 91,441 | 89,931 | ||||||
Adjustment to reconcile to reported Net Income from Unconsolidated Equity Affiliate: | ||||||||
Deferred income tax benefit | 21,348 | 23,415 | ||||||
Net Income Equity Affiliate | 70,093 | 66,516 | ||||||
Equity interest in unconsolidated equity affiliate | 40 | % | 40 | % | ||||
Income before amortization of excess basis in equity affiliate | 28,037 | 26,606 | ||||||
Amortization of excess basis in equity affiliate | (2,530 | ) | — | |||||
Net income from unconsolidated equity affiliate | $ | 25,507 | $ | 26,606 | ||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
Current assets | $ | 464,904 | $ | 206,907 | ||||
Property and equipment | 190,613 | 200,376 | ||||||
Other assets | 38,738 | 23,415 | ||||||
Current liabilities | 287,491 | 122,896 | ||||||
Other liabilities | 5,964 | 5,420 | ||||||
Net equity | 400,800 | 302,382 |
S-22
Year Ended | ||||
December 31, | ||||
2007 | ||||
(in thousands) | ||||
Operating Revenues | $ | 7,392 | ||
Net Income | $ | 527 | ||
Equity interest in unconsolidated equity affiliate | 45 | % | ||
Net income from unconsolidated equity affiliate | 237 | |||
Amortization of fair value of intangibles | (656 | ) | ||
Net loss from unconsolidated equity affiliate | $ | (419 | ) | |
December 31, | ||||
2007 | ||||
Current assets | $ | 3,995 | ||
Total assets | 14,846 | |||
Current liabilities | 2,100 | |||
Total liabilities | 2,100 |
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.
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.
S-23
S-20S-24
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, 2007 | ||||||||||||||||||||||||||||||||
Revenues | $ | 18,825 | $ | 28,576 | $ | 27,834 | $ | 30,860 | $ | — | $ | — | $ | — | $ | 11,217 | ||||||||||||||||
Expenses | (13,901 | ) | (19,911 | ) | (20,037 | ) | (18,619 | ) | (6,951 | ) | (7,798 | ) | (6,069 | ) | (9,935 | ) | ||||||||||||||||
Non-operating income (expense) | (1,864 | ) | (2,288 | ) | 44,056 | (1,743 | ) | (38 | ) | 353 | 15,076 | 35,059 | ||||||||||||||||||||
Income from consolidated companies before income taxes and minority interests | 3,060 | 6,377 | 51,853 | 10,498 | ||||||||||||||||||||||||||||
Income (loss) before income taxes and minority interests | (6,989 | ) | (7,445 | ) | 9,007 | 36,341 | ||||||||||||||||||||||||||
Income tax expense | 1,056 | 3,104 | 3,603 | 1,894 | 114 | 52 | 863 | 5,283 | ||||||||||||||||||||||||
Income before minority interests | 2,004 | 3,273 | 48,250 | 8,604 | ||||||||||||||||||||||||||||
Income (loss) before minority interests | (7,103 | ) | (7,497 | ) | 8,144 | 31,058 | ||||||||||||||||||||||||||
Minority interests | 887 | 1,216 | 1,367 | 2,498 | (637 | ) | (736 | ) | 2,524 | 17,909 | ||||||||||||||||||||||
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 | |||||||||||||||||||||||||
Income (loss) from consolidated companies | (6,466 | ) | (6,761 | ) | 5,620 | 13,149 | ||||||||||||||||||||||||||
Net income (loss) from unconsolidated equity affiliates | (39 | ) | (137 | ) | (235 | ) | 52,106 | |||||||||||||||||||||||||
Net income (loss) | $ | (15,458 | ) | $ | (11,413 | ) | $ | 46,410 | $ | 7,764 | $ | (6,505 | ) | $ | (6,898 | ) | $ | 5,385 | $ | 65,255 | ||||||||||||
Net income (loss) per common share: | ||||||||||||||||||||||||||||||||
Basic | $ | (0.44 | ) | $ | (0.32 | ) | $ | 1.31 | $ | 0.22 | $ | (0.17 | ) | $ | (0.18 | ) | $ | 0.15 | $ | 1.87 | ||||||||||||
Diluted | $ | (0.44 | ) | $ | (0.32 | ) | $ | 1.25 | $ | 0.21 | $ | (0.17 | ) | $ | (0.18 | ) | $ | 0.14 | $ | 1.78 | ||||||||||||
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, 2006* | ||||||||||||||||
Revenues | $ | 59,172 | $ | 334 | $ | — | $ | — | ||||||||
Expenses | (33,068 | ) | (7,796 | ) | (7,654 | ) | (10,414 | ) | ||||||||
Non-operating income (expense) | 1,940 | (13,419 | ) | (2,650 | ) | 258 | ||||||||||
Income (loss) before income taxes and minority interests | 28,044 | (20,881 | ) | (10,304 | ) | (10,156 | ) | |||||||||
Income tax expense | 14,762 | 40,810 | 5,338 | 7 | ||||||||||||
Income (loss) before minority interests | 13,282 | (61,691 | ) | (15,642 | ) | (10,163 | ) | |||||||||
Minority interests | 3,354 | (11,409 | ) | (2,044 | ) | (1,613 | ) | |||||||||
Net income (loss) | $ | 9,928 | $ | (50,282 | ) | $ | (13,598 | ) | $ | (8,550 | ) | |||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 0.27 | $ | (1.35 | ) | $ | (0.36 | ) | $ | (0.23 | ) | |||||
Diluted | $ | 0.26 | $ | (1.35 | ) | $ | (0.36 | ) | $ | (0.23 | ) | |||||
* | Financial information for 2006 has been restated to reflect retrospective application of the successful efforts method of accounting. See Note 1 — Organization and Summary of Significant Accounting Policies — Property and Equipment and Change in Accounting Principle. The effect of the accounting change on net income for the three months ended March 31, 2006 was a decrease of $3.9 million, net of income tax, or $0.10 per diluted share. |
S-25
S-21
TABLE I — |
United States | United States | |||||||||||||||||||||||||||||||
Venezuela | China | and Other | Total | Venezuela | China | and Other | Total | |||||||||||||||||||||||||
Year Ended December 31, 2004 | ||||||||||||||||||||||||||||||||
Development costs | $ | 39,161 | $ | — | $ | — | $ | 39,161 | ||||||||||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||||||||||||||||||
Acquisition costs | $ | — | $ | 160 | $ | 304 | $ | 464 | ||||||||||||||||||||||||
Exploration costs | 10 | 53 | — | 63 | — | 204 | — | 204 | ||||||||||||||||||||||||
$ | 39,171 | $ | 53 | $ | — | $ | 39,224 | $ | — | $ | 364 | $ | 304 | $ | 668 | |||||||||||||||||
Year Ended December 31, 2003 | ||||||||||||||||||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||||||||||||||||||
Acquisition costs | $ | — | $ | 35 | $ | — | $ | 35 | ||||||||||||||||||||||||
Development costs | $ | 58,079 | $ | — | $ | 2 | $ | 58,081 | 501 | — | — | 501 | ||||||||||||||||||||
Exploration costs | 11 | 39 | 133 | 183 | ||||||||||||||||||||||||||||
$ | 58,090 | $ | 39 | $ | 135 | $ | 58,264 | $ | 501 | $ | 35 | $ | — | $ | 536 | |||||||||||||||||
Year Ended December 31, 2002 | ||||||||||||||||||||||||||||||||
Year Ended December 31, 2005 | ||||||||||||||||||||||||||||||||
Acquisition costs | $ | — | $ | 42 | $ | — | $ | 42 | ||||||||||||||||||||||||
Development costs | �� | $ | 49,163 | $ | 120 | $ | 577 | $ | 49,860 | 8,912 | — | — | 8,912 | |||||||||||||||||||
Exploration costs | 794 | (149 | ) | 88 | 733 | |||||||||||||||||||||||||||
$ | 49,957 | $ | (29 | ) | $ | 665 | $ | 50,593 | $ | 8,912 | $ | 42 | $ | — | $ | 8,954 | ||||||||||||||||
United States | United States | |||||||||||||||||||||||||||||||
Venezuela | China | and Other | Total | Venezuela(a) | China(b) | and Other | Total | |||||||||||||||||||||||||
Year Ended December 31, 2004 | ||||||||||||||||||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||||||||||||||||||
Costs excluded from amortization | $ | — | $ | 2,859 | $ | 304 | $ | 3,163 | ||||||||||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||||||||||||||||||
Proved property costs | $ | 608,225 | $ | 13,454 | $ | — | $ | 621,679 | $ | — | $ | 13,532 | $ | — | $ | 13,532 | ||||||||||||||||
Costs excluded from amortization | — | 2,900 | — | 2,900 | — | 2,900 | — | 2,900 | ||||||||||||||||||||||||
Oilfield inventories | 6,503 | — | — | 6,503 | — | — | — | — | ||||||||||||||||||||||||
Less accumulated depletion and impairment | (432,302 | ) | (13,454 | ) | — | (445,756 | ) | — | (13,532 | ) | — | (13,532 | ) | |||||||||||||||||||
$ | 182,426 | $ | 2,900 | $ | — | $ | 185,326 | $ | — | $ | 2,900 | $ | — | $ | 2,900 | |||||||||||||||||
December 31, 2003 | ||||||||||||||||||||||||||||||||
Year Ended December 31, 2005 | ||||||||||||||||||||||||||||||||
Proved property costs | $ | 569,055 | $ | 13,401 | $ | — | $ | 582,456 | $ | 617,137 | $ | 13,497 | $ | — | $ | 630,634 | ||||||||||||||||
Costs excluded from amortization | — | 2,900 | — | 2,900 | — | 2,900 | — | 2,900 | ||||||||||||||||||||||||
Oilfield inventories | 8,266 | — | — | 8,266 | 8,150 | — | — | 8,150 | ||||||||||||||||||||||||
Less accumulated depletion and impairment | (398,206 | ) | (13,401 | ) | — | (411,607 | ) | (473,496 | ) | (13,497 | ) | — | (486,993 | ) | ||||||||||||||||||
$ | 179,115 | $ | 2,900 | $ | — | $ | 182,015 | $ | 151,791 | $ | 2,900 | $ | — | $ | 154,691 | |||||||||||||||||
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 investment in equity affiliates effective April 1, 2006. | |
(b) | SeeNote 8 — China Operations. |
S-22S-26
United States | 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 | |||||||||||||||||||
Venezuela | China | and Other | Total | |||||||||||||||||
Year ended December 31, 2004 | ||||||||||||||||||||
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 | $ | 186,066 | $ | — | $ | — | $ | 186,066 | $ | 236,941 | ||||||||||
Expenses: | ||||||||||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 33,297 | — | 214 | 33,511 | 39,969 | |||||||||||||||
Depletion | 34,108 | — | — | 34,108 | 41,175 | |||||||||||||||
Income tax expense | 38,968 | — | — | 38,968 | 65,943 | |||||||||||||||
Total expenses | 106,373 | — | 214 | 106,587 | 147,087 | |||||||||||||||
Results of operations from oil and natural gas producing activities | $ | 79,693 | $ | — | $ | (214 | ) | $ | 79,479 | $ | 89,854 | |||||||||
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. |
Significant Accounting Policies — Organization.
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
S-27
The 2006 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. SeeNote 1 — Organization and Summary of Significant Accounting Policies - Organization. Reserves for Petrodelta are reflected in the following sectionAdditional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Venezuela Equity Affiliate as of December 31, 2007 and 2006, TABLE IV — Quantities of Oil and Natural Gas Reserves.
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 | |||||||||||
Minority | ||||||||||||
Proved Reserves-Crude oil, condensate, | Interest in | |||||||||||
and natural gas liquids (MBbls) | Venezuela | Venezuela | Net Total | |||||||||
(in thousands) | ||||||||||||
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. |
S-24S-28
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 | ||||||||||||
Proved Reserves-Crude oil, condensate, | Interest in | |||||||||||
and natural gas liquids (MBbls) | Venezuela | Venezuela | Net Total | |||||||||
(in thousands) | ||||||||||||
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 | ||||||||
TABLE V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities
(a) | Includes primarily Contractually Restricted Reserves as well as other minor revisions. |
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at: | ||||||||||||
December 31, 2005 | 35,311 | (7,062 | ) | 28,249 | ||||||||
January 1, 2005 | 45,488 | (9,098 | ) | 36,390 | ||||||||
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. |
Proved Developed Reserves-Natural gas (MMcf) at: | ||||||||||||
December 31, 2005 | 58,918 | (11,784 | ) | 47,134 | ||||||||
January 1, 2005 | 80,897 | (16,179 | ) | 64,718 |
TABLE V — | Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities |
S-25S-29
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 | ||||||||||
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 | |||||
(a) | Proved reserves do not include Contractually Restricted Reserves. |
TABLE VI — | Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves |
Net Venezuela | ||||||||
2006(a) | 2005 | |||||||
(in thousands) | ||||||||
Standardized Measure at January 1 | $ | 329,438 | $ | 544,980 | ||||
Sales of oil and natural gas, net of related costs | (40,361 | ) | (124,638 | ) | ||||
Revisions to estimates of proved reserves | ||||||||
Net changes in prices, development and production costs | — | 262,852 | ||||||
Quantities | — | (365,565 | ) | |||||
Extensions, discoveries and improved recovery, net of future costs | — | — | ||||||
Accretion of discount | — | 80,202 | ||||||
Net change in income taxes | — | 109,030 | ||||||
Development costs incurred | 501 | 7,130 | ||||||
Changes in timing and other | (289,578 | ) | (184,553 | ) | ||||
Standardized Measure at December 31 | $ | — | $ | 329,438 | ||||
(a) | All reserves have been removed pending conversion to Petrodelta. |
TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
Net Venezuela | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(amounts in thousands) | ||||||||||||
Present Value at January 1 | $ | 366,770 | $ | 317,799 | $ | 163,328 | ||||||
Sales of oil and natural gas, net of related costs | (122,215 | ) | (59,720 | ) | (76,098 | ) | ||||||
Revisions to estimates of Proved Reserves | ||||||||||||
Net changes in prices, development and production costs | 333,237 | 76,037 | 310,043 | |||||||||
Quantities | (7,597 | ) | (1,584 | ) | 611 | |||||||
Extensions, discoveries and improved recovery, net of future costs | — | 4,971 | 89,670 | |||||||||
Accretion of discount | 54,531 | 48,128 | 17,621 | |||||||||
Net change in income taxes | (78,504 | ) | (15,053 | ) | (150,603 | ) | ||||||
Development costs incurred | 31,329 | 46,463 | 40,532 | |||||||||
Changes in timing and other | (32,571 | ) | (50,271 | ) | (77,305 | ) | ||||||
Present Value at December 31 | $ | 544,980 | $ | 366,770 | $ | 317,799 | ||||||
S-26S-30
Geoilbent (34
December 31, 2007 and 2006.
Petrodelta | ||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||
Development costs | $ | 976 | ||||||||||||||
Exploration costs | — | |||||||||||||||
Total Equity | $ | 976 | ||||||||||||||
Arctic Gas | Geoilbent | Affiliates | ||||||||||||||
Year Ended September 25, 2003 | ||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||
Development costs | $ | — | $ | 3,474 | $ | 3,474 | $ | 217 | ||||||||
Exploration costs | — | 1,034 | 1,034 | — | ||||||||||||
$ | — | $ | 4,508 | $ | 4,508 | $ | 217 | |||||||||
Year Ended September 30, 2002 | ||||||||||||||||
Development costs | $ | — | $ | 8,599 | $ | 8,599 | ||||||||||
Exploration costs | 16,156 | 498 | 16,654 | |||||||||||||
$ | 16,156 | $ | 9,097 | $ | 25,253 | |||||||||||
Total Equity | Petrodelta | |||||||||||||||
Arctic Gas | Geoilbent | Affiliates | ||||||||||||||
September 25, 2003 | ||||||||||||||||
December 31, 2007 | ||||||||||||||||
Proved property costs | $ | — | $ | 102,753 | $ | 102,753 | $ | 59,820 | ||||||||
Unproved property costs | 7,247 | |||||||||||||||
Costs excluded from amortization | (976 | ) | ||||||||||||||
Oilfield inventories | — | 2,530 | 2,530 | 4,426 | ||||||||||||
Less accumulated depletion and impairment | — | (72,333 | ) | (72,333 | ) | (11,063 | ) | |||||||||
$ | — | $ | 32,950 | $ | 32,950 | $ | 59,454 | |||||||||
September 30, 2002 | ||||||||||||||||
December 31, 2006 | ||||||||||||||||
Proved property costs | $ | — | $ | 94,404 | $ | 94,404 | $ | 58,849 | ||||||||
Unproved property costs | 7,247 | |||||||||||||||
Costs excluded from amortization | — | 272 | 272 | (217 | ) | |||||||||||
Oilfield inventories | — | 2,348 | 2,348 | 2,650 | ||||||||||||
Less accumulated depletion and impairment | — | (31,440 | ) | (31,440 | ) | (5,317 | ) | |||||||||
$ | — | $ | 65,584 | $ | 65,584 | $ | 63,212 | |||||||||
S-31
Petrodelta | ||||||||||||||||
Year ended December 31, 2007 | ||||||||||||||||
Oil and natural gas revenues | $ | 107,429 | ||||||||||||||
Royalty | (36,751 | ) | ||||||||||||||
Total Equity | 70,678 | |||||||||||||||
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 | 7,601 | ||||||||||||
Depletion | — | 6,215 | 6,215 | 5,746 | ||||||||||||
Write-down of oil and gas properties | — | 32,300 | 32,300 | |||||||||||||
Income tax expense | — | 2,073 | 2,073 | 23,714 | ||||||||||||
Total expenses | — | 56,676 | 56,676 | 37,061 | ||||||||||||
Results of operations from oil and natural gas producing activities | $ | — | $ | (28,800 | ) | $ | (28,800 | ) | $ | 33,617 | ||||||
Year ended December 31, 2006 | ||||||||||||||||
Oil and natural gas revenues | $ | 90,695 | ||||||||||||||
Royalty | (30,973 | ) | ||||||||||||||
59,722 | ||||||||||||||||
Expenses: | ||||||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 7,273 | |||||||||||||||
Depletion | 5,317 | |||||||||||||||
Income tax expense | 15,430 | |||||||||||||||
Total expenses | 28,020 | |||||||||||||||
Results of operations from oil and natural gas producing activities | $ | 31,702 | ||||||||||||||
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
Petrodelta.
S-32
Minority | ||||||||||||
Proved Reserves-Crude oil, condensate, | Interest in | 32% | ||||||||||
and natural gas liquids (MBbls) | HNR Finance | Venezuela | Net Total | |||||||||
(in thousands) | ||||||||||||
Year ended December 31, 2007 | ||||||||||||
Proved Reserves at January 1, 2007 | — | — | — | |||||||||
Additions(a) | 50,085 | (10,017 | ) | 40,068 | ||||||||
Production | (2,824 | ) | 565 | (2,259 | ) | |||||||
Proved Reserves at end of the year | 47,261 | (9,452 | ) | 37,809 | ||||||||
(a) | Petrodelta was formed in 2007 |
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at: | ||||||||||||
December 31, 2007 | 14,779 | (2,956 | ) | 11,823 | ||||||||
Proved Reserves-Natural gas (MMcf) | ||||||||||||
Year ended December 31, 2007 | ||||||||||||
Year ended December 31, 2007 | ||||||||||||
Proved Reserves at January 1, 2007 | — | — | — | |||||||||
Additions(a) | 50,019 | (10,004 | ) | 40,015 | ||||||||
Production | (6,935 | ) | 1,387 | (5,548 | ) | |||||||
Proved Reserves at end of the year | 43,084 | (8,617 | ) | 34,467 | ||||||||
(a) | Petrodelta was formed in 2007 |
Proved Developed Reserves-Natural gas (MMcf) at: | ||||||||
December 31, 2007 | 7,755 | (1,551 | ) | 6,204 |
S-28S-33
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 |
TABLE V — | Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserve Quantities |
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.
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 The table shown below represents HNR Finance’s net interest in Petrodelta. We report the Standardized Measureresults of Discounted Future Net Cash Flows from Proved ReservesRyder Scott Company L.P. independent engineering evaluation at December 31 to provide comparability with our Venezuelan 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 | ||||
Minority | ||||||||||||
Interest in | ||||||||||||
HNR Finance | Venezuela | Net Total | ||||||||||
(in thousands) | ||||||||||||
December 31, 2007 | ||||||||||||
Future cash inflows from sales of oil and gas | $ | 3,650,110 | $ | (730,022 | ) | $ | 2,920,088 | |||||
Future production costs | (685,368 | ) | 137,074 | (548,294 | ) | |||||||
Future development costs | (358,759 | ) | 71,752 | (287,007 | ) | |||||||
Future income tax expenses | (1,274,005 | ) | 254,801 | (1,019,204 | ) | |||||||
Future net cash flows | 1,331,978 | (266,395 | ) | 1,065,583 | ||||||||
Effect of discounting net cash flows at 10% | (677,756 | ) | 135,551 | (542,205 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 654,222 | $ | (130,844 | ) | $ | 523,378 | |||||
TABLE VI — Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves |
S-30S-34
HARVEST NATURAL RESOURCES, INC. (Registrant) | ||||
Date: | By: | /s/ | ||
Chief Executive Officer | ||||
Signature | Title | |
/s/ | Director, President and Chief Executive Officer | |
/s/ Steven W. TholenSteven W. Tholen (Principal Financial Officer) | Senior Vice President - Finance, Chief Financial Officer and Treasurer | |
/s/ Kurt A. NelsonKurt A. Nelson (Principal Accounting Officer) | Vice President-Controller, Chief Accounting Officer | |
/s/ Stephen D. Chesebro’Stephen D. Chesebro’ | Chairman of the Board and Director | |
/s/ John U. ClarkeJohn U. Clarke | Director | |
/s/ | Director | |
/s/ H. H. HardeeH. H. Hardee | Director | |
/s/ | Director | |
/s/ Patrick M. MurrayPatrick M. Murray | Director | |
/s/ J. Michael StinsonJ. Michael Stinson | Director |
S-31S-35
Additions | Additions | |||||||||||||||||||||||||||||||||||||||
Balance at | Charged to | Deductions | Balance at | Balance at | Charged to Other | Deductions From | Balance at End of | |||||||||||||||||||||||||||||||||
Beginning | Charged to | Other | From | End of | Beginning of Year | Charged to Income | Accounts | Reserves | Year | |||||||||||||||||||||||||||||||
of Year | Income | Accounts | Reserves | Year | ||||||||||||||||||||||||||||||||||||
At December 31, 2004 | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2007 | ||||||||||||||||||||||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||||||||||||||||||||||
Accounts receivable | $ | 3,355 | $ | — | $ | — | $ | 598 | $ | 2,757 | $ | 2,757 | $ | — | $ | — | $ | — | $ | 2,757 | ||||||||||||||||||||
Deferred tax valuation allowance | 48,365 | (3,284 | ) | — | — | 45,081 | 32,809 | 32,809 | — | — | ||||||||||||||||||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 | 1,350 | — | — | — | 1,350 | ||||||||||||||||||||||||||||||
At December 31, 2003 | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2006 | ||||||||||||||||||||||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||||||||||||||||||||||
Accounts receivable | $ | 3,525 | $ | 205 | $ | — | $ | 375 | $ | 3,355 | $ | 2,757 | $ | — | $ | — | $ | — | $ | 2,757 | ||||||||||||||||||||
Deferred tax valuation allowance | 39,146 | 9,219 | — | — | 48,365 | 27,363 | 5,446 | — | — | 32,809 | ||||||||||||||||||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 | 1,350 | — | — | — | 1,350 | ||||||||||||||||||||||||||||||
At December 31, 2002 | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2005 | ||||||||||||||||||||||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||||||||||||||||||||||
Accounts receivable | $ | 6,512 | $ | 289 | $ | — | $ | 3,276 | $ | 3,525 | $ | 2,757 | $ | — | $ | — | $ | — | $ | 2,757 | ||||||||||||||||||||
Deferred tax valuation allowance | 19,700 | 20,577 | — | 1,131 | 39,146 | 40,492 | (13,129 | ) | — | — | 27,363 | |||||||||||||||||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 | 1,350 | — | — | — | 1,350 |
S-32S-36
LLC GeoilbentFinancial Statements30 September 2003
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors andOwners 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 Federation2 March 2004
LLC GEOILBENTBALANCE 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 GEOILBENTSTATEMENTS 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 GEOILBENTSTATEMENTS 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 GEOILBENTSTATEMENT 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 GEOILBENTNOTES 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 GEOILBENTNOTES 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 GEOILBENTNOTES 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 GEOILBENTNOTES 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 GEOILBENTNOTES 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 GEOILBENTNOTES 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 GEOILBENTNOTES 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:
3.1 | ||||
The aggregate maturities of long-term debt outstanding at 30 September 2003 are as follows:
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 GEOILBENTNOTES 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 GEOILBENTNOTES 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:
As a result of the application of EITF No. 92-4 and No. 92-8, the valuation allowance related to property, plant and equipment was reduced to zero and a deferred tax liability of USD 8.1 million recorded on 1 January 2003 (Note 2), with no effect on income as the adjustment was recorded as part of the currency translation adjustment as of 1 January 2003. A subsequent ceiling test writedown in March resulted in the recognition of an additional deferred tax asset of USD 10.8 million of which USD 7.6 million and USD 3.2 million were credited as a deferred tax benefit and an increase to the DTA valuation allowance, respectively.
Deferred income tax assets are classified as follows:
Thousands of US dollars | 30 September 2003 | 30 September 2002 | ||||||
Deferred income tax, current | 966 | 1,806 | ||||||
Deferred income tax, non-current | — | 696 | ||||||
Total net deferred tax asset | 966 | 2,502 | ||||||
9
LLC GEOILBENTNOTES TO THE FINANCIAL STATEMENTS(expressed in US Dollars except as indicated)
Note 14: Taxes (continued)
Taxes other than income tax.The Company is subject to a number of taxes other than on income which are detailed below.
Thousands of US dollars | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||
Export duties | 8,464 | 5,376 | 10,922 | |||||||||
Excise tax | — | 535 | 1,548 | |||||||||
Royalty | — | 2,254 | 4,867 | |||||||||
Mineral restoration tax | 377 | 885 | 4,596 | |||||||||
Road users tax | 203 | 860 | 1,427 | |||||||||
Unified production tax | 19,056 | 14,221 | — | |||||||||
Property taxes | 2,263 | 1,994 | 1,424 | |||||||||
Taxes recovery | (7,017 | ) | — | — | ||||||||
Other taxes | 2,279 | 1,532 | 1,227 | |||||||||
Total taxes other than income tax | 25,625 | 27,657 | 26,011 | |||||||||
Beginning 1 January 2002, mineral restoration tax, royalty tax and excise tax on crude oil production were abolished and replaced by the unified natural resources production tax. From 1 January 2004 through 31 December 2006, the base rate for the unified natural resources production tax is set at RR 347 per metric ton of crude oil produced, and is to be adjusted depending on the market price of Urals blend and the RR/USD exchange rate. The tax becomes nil if the Urals blend price falls to or below USD 8.00 per barrel. From 1 January 2007, the unified natural resources production tax rate is set by law at 16.5 percent of crude oil revenues recognized by the Company based on Tax Regulations of the Russian Federation.
During the year ended 30 September 2003, the Company pursued its claim of overpayment of mineral restoration taxes (MRT) paid during the period from 1999 to 2001 of approximately RR 211 million (USD 7.0 million), plus approximately RR 4 million (USD 0.1 million) in related penalties paid. During the year, the regional courts ruled in favour of the Company and, accordingly, the Company and the tax authorities agreed to offset the amounts awarded against the Company’s unified production taxes payable.
Note 15: Related Party Transactions
As of 30 September 2003 and 2002, the Company had the following balances with its stockholders. These balances are included in the balance sheet within accounts receivable, accounts payable and long-term debt as appropriate.
Thousand of US Dollars | 30 September 2003 | 30 September 2002 | ||||||
Accounts receivable | ||||||||
Purneftegasgeologia and affiliated entities | 19 | 63 | ||||||
Accounts payable | ||||||||
Purneftegasgeologia and affiliated entities | 183 | 574 | ||||||
YUKOS | 2,111 | — | ||||||
Harvest Natural Resources | — | 3,354 | ||||||
Purneftegas and affiliated entities | — | 22 | ||||||
Long-term debt | ||||||||
Harvest Natural Resources | — | 2,500 | ||||||
YUKOS | 2,500 | — | ||||||
Minley | 5,000 | 5,000 |
10
LLC GEOILBENTNOTES 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 GEOILBENTNOTES 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 GEOILBENTSupplemental 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 GEOILBENTSUPPLEMENTAL 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 GEOILBENTSUPPLEMENTAL 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 GEOILBENTSUPPLEMENTAL 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
Index to Exhibits
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 | Restated Bylaws as of | |||
4.1 | Form of Common Stock Certificate. | |||
4.2 | Certificate of Designation, Rights and Preferences of the Series | |||
4.3 | Third Amended and Restated Rights Agreement, dated as of | |||
10.1 | ||||
2001 Long Term Stock Incentive Plan. (Incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 filed on April 9, 2002 (Registration Statement No. 333-85900).) | ||||
10.2 | ||||
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).) |
Form of Indemnification Agreement between Harvest Natural Resources, Inc. and | ||||
10.4 | Form of 2004 Long Term Stock Incentive Plan Stock Option | |||
10.5 | Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock | |||
10.6 | Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock | |||
10.7† | 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.) | |||
10.8† | 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.) | |||
10.9† | 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.) | |||
10.10† | 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.) | |||
10.11† | 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.) | |||
10.12† | 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.) | |||
10.13† | 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.) | |||
10.14 | 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].) | |||
10.15 | 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.) | |||
10.16 | 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.) | |||
10.17 | 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.) |
10.18† | 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.) | |||
10.19† | 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.) | |||
10.20 | 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. (Incorporated by reference to Exhibit 10.32 to our Form 10-K filed on March 13, 2007, File No. 1-10762.) | |||
10.21 | Form of 2006 Long Term Incentive Plan Stock Option Agreement — Five Year Vesting, Seven Year Term. (Incorporated by reference to Exhibit 10.33 to our Form 10-K filed on March 13, 2007, File No. 1-10762.) | |||
10.22 | Amendment to Harvest Natural Resources 2006 Long Term Incentive Plan adopted July 19, 2006. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on May 3, 2007, File No. 1-10762.) | |||
10.23† | Employment Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) | |||
10.24† | Stock Option Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) | |||
10.25† | Employee Restricted Stock Agreement dated May 7, 2007 between Harvest Natural Resources, Inc. and Keith L. Head. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) | |||
10.26† | Consulting Agreement dated July 16, 2007 between Harvest Natural Resources, Inc. and Kerry R. Brittain. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on July 25, 2007, File No. 1-10762.) | |||
10.27 | Contract for Conversion to a Mixed Company between Corporación Venezolana del Petróleo, S.A., Harvest-Vinccler, S.C.A. and HNR Finance B.V. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on November 1, 2007, File No. 1-10762.) | |||
10.28† | Separation Agreement dated November 16, 2007 between Harvest Natural Resources, Inc. and Byron A. Dunn. | |||
21.1 | List of subsidiaries. | |||
23.1 | Consent of PricewaterhouseCoopers LLP — | |||
23.2 | Consent of | |||
23.3 | Consent of Ryder Scott Company, | |||
31.1 | Certification | |||
31.2 | Certification |
32.1 | Certification accompanying Annual Report on Form 10-K pursuant to Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. Section 1350 executed by James A. Edmiston, President and Chief Executive Officer. | |||
32.2 | Certification |
† | Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item |