ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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) | |
Houston, Texas | ||
(Address of principal executive offices) | (Zip Code) |
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 |
o
þ
State theþ
30, 2006 was: $503,574,368.
37,536,523.
HARVEST NATURAL RESOURCES, INC.
FORM 10-K
TABLE OF CONTENTS
Page | ||||||||
1 | ||||||||
11 | ||||||||
17 | ||||||||
17 | ||||||||
17 | ||||||||
18 | ||||||||
Market for Registrant’s Common Equity, | ||||||||
Selected Financial Data | ||||||||
Quantitative and Qualitative Disclosures About Market Risk | ||||||||
Financial Statements and Supplementary Data | ||||||||
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | ||||||||
Controls and Procedures | ||||||||
31 | ||||||||
32 | ||||||||
32 | ||||||||
32 | ||||||||
32 | ||||||||
33 | ||||||||
Financial Statements | ||||||||
S-29 | ||||||||
Note Payable Agreement | ||||||||
Form of 2006 Long Term Incentive Plan Stock Option Agreement | ||||||||
List of Subsidiaries | ||||||||
Consent of PricewaterhouseCoopers LLP | ||||||||
Consent of Ryder Scott Company, LP | ||||||||
Certification Pursuant to Section 302 by President and CEO | ||||||||
Certification Pursuant to Section 302 by Sr. VP, CFO and Treasurer | ||||||||
Certification Pursuant to Section 906 by President and CEO | ||||||||
Certification Pursuant to Section 906 by Sr. VP, CFO and Treasurer |
1
At the end of Item 1 is a glossary of terms.
General
1
events during 2006.
As of December 31, 2003,2006, we had total assets of $374.3$422.7 million. We had unrestricted cash in excess of long term debt in the amount of $41.9$148.1 million, long-term debt of $67.0 million, total revenues of $59.5 million and net cash used in operating activities of $24.4 million. For the year ended December 31, 2003,2005, we had total assets of $400.8 million. We had cash in the amount of $163.0 million, no long-term debt, total revenues of $106.1$236.9 million and net cash provided by operating activities of $38.5 million,$114.7 million.
• | maintain financial prudence and rigorous investment criteria; | ||
• | access capital markets; | ||
• | create a diversified portfolio of assets; | ||
• | preserve our financial flexibility; | ||
• | use our experience, skills and relationships to acquire new projects; and | ||
• | keep our organizational capabilities in line with our rate of growth. |
2
www.sec.gov.
Business Strategy
Our business strategy is
In Venezuela, we intend to deliver more operating cash flow through the efficient management of our capital expenditure programs and cost structure. We completed the first phase of our gas project at the South Monagas Unit in November 2003 on timecomprising the Uracoa, Tucupita and within budget and commenced gas sales on November 25, 2003. This is an important milestone of our strategy because it diversifies our revenues and cash flow, and develops vital market outlets to support further development of untapped reserves of natural gas in Eastern Venezuela. Our Venezuelan producing properties generate net cash from operating activities in excess of projected capital expenditures. We expect to reinvest this cash in new growth opportunities in Venezuela. In November 2003, we executed a Memorandum of Understanding with PDVSA to submit a plan of development forBombal fields (the “SMU fields”) pending the previously developed Temblador Field and the discovered, yet undeveloped, El Salto Field. Under the termscompletion of the Memorandum of Understanding, we can submit a plan of development for developmentconversion of the fields under Venezuela’s Organic Hydrocarbon Law.OSA to Petrodelta. We are also in discussionsbegan the year with PDVSA for the developmentaverage oil deliveries of the nearby Isleno Field.
We are seeking to diversify our cash flow outside22,000 barrels of Venezuela as events there demonstrated the risks of our concentration in Venezuela when we lost six weeks of production in the first part of 2003. We seek operational and financial control, good minority interest partners, access to competitive oil and gas markets, and where possible, reliable export facilities and infrastructure. We seek low entry cost projects that need additional funding, execution skills and well reasoned development.
In Russia, we continue to evaluate a number of options to invest in known discoveries which remain undeveloped or under-developed. In September 2003, we sold our 34 percent minority equity investment in our Russian company Geoilbent. As a minority interest owner, our continuing investment in Geoilbent was determined to be inconsistent with our objective of investing in properties in which we have operating and financial control.
We intend to continue to identify, acquire and exploit known oilper day (“Bopd”) and natural gas deliveries of 56 million cubic feet a day (“MMCFpd”). The fields in our current areas of activity while maintaining our financial strengthcurrently produce approximately 17,000 Bopd and flexibility. To accomplish this, we intend to:
3
Our ability to successfully execute our strategy is subject to significant risks including, among other things, operating risks, political risks, legal risks and financial risks. SeeItem 7 – Management’s Discussion and Analysis of Financial Conditions and Results of Operationsand other information set forth elsewhere in this Form 10-K for a description of these and other risk factors.
Operations
The following table summarizes our Proved Reserves,Venezuela proved reserves, drilling and production activity, and financial operating data by principal geographic area at the end of each of the years endingended December 31, 2003, 20022006, 2005 and 2001. All2004. The Venezuelan reserves are attributable to an operating service agreementour OSA between Benton-VincclerHarvest Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela. We disposed of our Russian investments partly in 2002 and partly in 2003. Geoilbent and Arctic Gas were accounted for under the equity method and were included at their respective ownership interests in our consolidated financial statements for the periods in which we owned such investments. Our year-end financial information contains results from our Russian operations based on a twelve-month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2003, 2002 and 2001 reflect results from Geoilbent until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and 2001, and from Arctic Gas, until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001.
We own 80 percent of Benton-Vinccler. The reserve information presented below is net of a 20 percent deduction for the minority interest in Benton-Vinccler.Harvest Vinccler. Drilling and production activity and financial data are reflected without deduction for minority interest. ReservesFor 2004 and 2005, the year-end reserves include production projected through the endtermination of the operating service agreementOSA in 2012. We have submitted a request for extension underIn April 2006, the force majeure provisions of our contract. The Venezuelan national civil work stoppage required Benton-Vinccler to shut-in production for approximately two months. We believegovernment unilaterally terminated the two months representing this delay will be added to the original term of our agreement.
43
Benton-Vinccler | Harvest Vinccler | |||||||||||||||||||||||
Year Ended December 31, | Year Ended | |||||||||||||||||||||||
2003 | 2002 | 2001 | 12/31/06 | 12/31/05 | 12/31/04 | |||||||||||||||||||
(Dollars in 000’s) | (Dollars in 000’s) | |||||||||||||||||||||||
RESERVE INFORMATION | ||||||||||||||||||||||||
RESERVE INFORMATION: | ||||||||||||||||||||||||
Proved Reserves (MBoe) | 96,364 | 102,534 | 83,611 | — | 36,105 | 84,418 | ||||||||||||||||||
Discounted future net cash flow attributable to proved reserves, before income taxes | $ | 545,308 | $ | 481,284 | $ | 176,210 | ||||||||||||||||||
Standardized measure of future net cash flows | $ | 366,770 | $ | 317,799 | $ | 163,328 | ||||||||||||||||||
Standardized measure of discounted future net cash flows | $ | — | $ | 329,438 | $ | 544,980 | ||||||||||||||||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||||||||||||||||||
Gross wells drilled | 3 | 13 | 8 | — | 1 | 16 | ||||||||||||||||||
Average daily production (Boe) | 20,130 | 26,598 | 26,788 | 29,389 | 35,732 | 36,418 | ||||||||||||||||||
FINANCIAL DATA: | ||||||||||||||||||||||||
Oil and natural gas revenues | $ | 106,095 | $ | 126,731 | $ | 122,386 | $ | 59,506 | $ | 236,941 | $ | 186,066 | ||||||||||||
Expenses: | ||||||||||||||||||||||||
Operating expenses and taxes other than on income | 31,445 | 31,608 | 42,175 | 9,451 | 39,969 | 33,297 | ||||||||||||||||||
Depletion | 19,599 | 22,685 | 21,175 | 9,904 | 41,175 | 34,108 | ||||||||||||||||||
Income tax expense | 12,158 | 4,866 | 9,083 | |||||||||||||||||||||
Income tax expense(a) | 20,076 | 65,943 | 38,968 | |||||||||||||||||||||
Total expenses | 63,202 | 59,159 | 72,433 | 39,431 | 147,087 | 106,373 | ||||||||||||||||||
Results of operations from oil and natural gas producing activities | $ | 42,893 | $ | 67,572 | $ | 49,953 | $ | 20,075 | $ | 89,854 | $ | 79,693 | ||||||||||||
We owned 34 percent of Geoilbent, which we accounted for under the equity method. The following table presents our proportionate share of Geoilbent’s Proved Reserves (at September 30 for each respective year), drilling and production activity, and financial operating data for the period until it was sold on September 25, 2003, and for the twelve months ended September 30, 2002 and 2001.
Geoilbent | ||||||||||||
Year Ended September 30, | ||||||||||||
2003 | 2002 | 2001 | ||||||||||
(Dollars in 000’s) | ||||||||||||
RESERVE INFORMATION | ||||||||||||
Proved Reserves (MBbls) | (a | ) | 25,356 | 29,668 | ||||||||
Discounted future net cash flow attributable to proved reserves, before income taxes | (a | ) | $ | 117,229 | $ | 81,125 | ||||||
Standardized measure of future net cash flows | (a | ) | $ | 92,939 | $ | 70,648 | ||||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||||||
Gross development wells drilled | (a | ) | 6 | 39 | ||||||||
Net development wells drilled | (a | ) | 2 | 13 | ||||||||
Average daily production (Bbls) | 5,242 | 6,438 | 4,830 | |||||||||
FINANCIAL DATA: | ||||||||||||
Oil and natural gas revenues | $ | 27,876 | $ | 31,039 | $ | 34,261 | ||||||
Expenses: | ||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 16,088 | 16,902 | 16,083 | |||||||||
Depletion | 6,215 | 9,237 | 5,072 | |||||||||
Write-down of oil and gas properties | 32,300 | — | — | |||||||||
Income tax expense | 2,073 | 1,955 | 3,742 | |||||||||
Total expenses | 56,676 | 28,094 | 24,897 | |||||||||
Results of operations from oil and natural gas producing activities | $ | (28,800 | ) | $ | 2,945 | $ | 9,364 | |||||
(a) |
As
5
drilling and production activity, and financial operating data for the period until it was sold on April 12, 2002 and for the twelve months ended September 30, 2001.
Arctic Gas Company | ||||||||
Year Ended September 30, | ||||||||
2002 | 2001 | |||||||
(Dollars in 000’s) | ||||||||
RESERVE INFORMATION | ||||||||
Proved Reserves (MBoe) | (a | ) | 55,631 | |||||
Discounted future net cash flow attributable to proved reserves, before income taxes | (a | ) | $ | 108,400 | ||||
Standardized measure of future net cash flows | (a | ) | $ | 82,205 | ||||
DRILLING AND PRODUCTION ACTIVITY: | ||||||||
Gross wells reactivated | (a | ) | 2 | |||||
Average daily production (Bbls) | 189 | 502 | ||||||
FINANCIAL DATA: | ||||||||
Oil and natural gas revenues | $ | 3,554 | $ | 889 | ||||
Expenses: | ||||||||
Selling and distribution expenses | 1,429 | 1,166 | ||||||
Operating expenses and taxes other than on income | 1,673 | 2,215 | ||||||
Depletion | 139 | 311 | ||||||
Income tax expense | 19 | 80 | ||||||
Total expenses | 3,260 | 3,772 | ||||||
Results of operations from oil and natural gas producing activities | $ | 294 | $ | (2,883 | ) | |||
South Monagas Unit Venezuela (Benton-Vinccler)
General
The OSA was one of the original 33 operating service agreements entered into between PDVSA affiliates and private oil companies. Although it is our position that the OSA is still in place and natural gas operationswe continue in the South Monagas Unit are conducted by Benton-Vinccler, our 80 percent-owned subsidiary. The remaining 20 percentday-to-day operations of the outstanding capital stock of Benton-Vinccler is owned by Vinccler. Through our majority ownership of stock in Benton-Vinccler, we makeSMU fields, the Venezuelan government has terminated all operational and corporate decisions related to Benton-Vinccler, subject to certain super-majority provisions of Benton-Vinccler’s charter documents related to:
Vinccler has an extensive operating history in Venezuela. It provided Benton-Vinccler with initial financial assistance and significant construction services. Vinccler provided assistance with construction projects, governmental relations and labor relations during 2003.
services agreements effective April 2006.
6
ownership of all hydrocarbons in the fields. In addition, the PDVSA affiliate maintains full ownership of equipment and capital infrastructure following its installation.
The operating service agreementOSA provides for Benton-VincclerHarvest Vinccler to receive an operating fee for each barrel of crude oil delivered. It also provides Benton-VincclerHarvest Vinccler with the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannot exceed the maximum total fee per barrel set forth in the agreement. The operating fee is subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. TheHistorically, our maximum total fee is subject to quarterly adjustments to reflect changes inunder the averageOSA averaged approximately 48 percent of certain world crude oil prices. Since 1992, the maximum total fee received by Benton-Vinccler has approximated 48 percentprice of West Texas Intermediate crude oil (“WTI”) price.
. Under an amendment we signed in August 2005 to limit our fee, the fee has historically averaged approximately 47 percent of the price of WTI. In September 2002, Benton-VincclerHarvest Vinccler and PDVSA signed an amendment to the operating service agreement,OSA, providing for the delivery of up to 198 Bcfmillion cubic feet (“Bcf”) of natural gas through July 2012 at a price of $1.03 per Mcf. Naturalthousand standard cubic feet (“Mcf”). The OSA stipulated that all payments for oil and natural gas sales beganwere to be paid in November 2003U.S. Dollars. Despite these
4
At the endPetrodelta. Harvest Vinccler will fill its share of each quarter, Benton-Vinccler prepares an invoicemanagement positions with employees or secondees to PDVSA based on barrelsHarvest Vinccler. The General Manager of oil accepted by PDVSA during the quarter, using quarterly adjusted contract service fees per barrel. At the end of each quarter, Benton-Vinccler also prepares invoices for natural gas sales and Incremental Crude Oil. Payment is due under the invoicesPetrodelta will be appointed by the endBoard of Directors and will be in charge of the second month after the enddaily management of the quarter. Invoice amountsbusiness of Petrodelta and payments are denominatedwill have the power and duties customary to manage, direct and supervise the accounting of Petrodelta. CVP has the right to nominate the General Manager to Petrodelta while HNR Finance has the right to nominate the Technical and Operations Manager. CVP also has the right to nominate the Manager of Prevention and Loss Control.
Benton-Vinccler has constructed a 25-mile oil pipeline from its oil processing facilities at Uracoa to PDVSA’s storage facility,capital stock of Petrodelta that would alter the custody transfer point. The operating service agreement specifies that the oil stream may contain no more than one percent base sediment and one percent water. Quality measurements are conducted both at Benton-Vinccler’s facilities and at PDVSA’s storage facility.
With respect to gas sales, an initial capital investmentpercentage participation of approximately $27 million was required to build a 64-mile pipeline with a normal capacityHNR Finance or CVP; any liquidation or dissolution of 70 MMcfPetrodelta; any merger, consolidation or business combination of natural gas per day and a design capacityPetrodelta; disposition of 90 MMcf of natural gas per day, a gas gathering system, upgrades to the UM-2 plant facilities and new gas treatment and compression facilities. We completed the fabrication and construction process for the gas pipeline in late 2003. Benton-Vinccler borrowed $15.5 million under a project loan for the gas pipeline and related facilities and the remainder was funded from existing cash balances and internally generated cash flow. In addition, Benton-Vinccler has entered into long-term agreements for the leasing of compression, and the operation and maintenance of the gas treatment and compression facilities. The operating services agreement contains requirements for the measurement and quality of the natural gas delivered to PDVSA.
In August 1999, Benton-Vinccler sold its power generation facility located in the Uracoa and Tucupita Fields. Concurrently with the sale, Benton-Vinccler entered into a long-term power purchase agreement with the purchaser of the facility to provide for the electrical needs of the field throughout the remaining term of the operating service agreement.
Location and Geology
The South Monagas Unit extends across the southeasternall or any substantial part of the stateassets of Monagas and the southwestern part of the state of Delta Amacuro in eastern Venezuela. The South Monagas Unit is approximately 51 miles long and eight miles wide and consists of 157,843 acres, of which the fields comprise approximately one-half of the acreage. At December 31, 2003, Proved Reserves attributable to our Venezuelan operations were 120,455 MBoe (96,364 MBoe net to Harvest). This represented 100 percent of our Proved Reserves at year end. Benton-Vinccler has been primarily developing the Oficina sandsPetrodelta, except in the Uracoa Field. The Uracoa Field contains 66 percentordinary course of business; any financing agreement for an amount greater than $10 million; approval or modification of Petrodelta’s financial statements; creation of certain reserve funds; any distribution of dividends or return of paid-in surplus; changes to the South Monagas Unit’s Proved Reserves.
75
Drilling
Benton-Vinccler drilledpurchase of hydrocarbons with PPSA; contracts with shareholders or affiliates that are not at market price; any social investment in excess of the amount required by the Venezuelan government; any waiver of material rights or actions with respect to litigation involving more than $1 million; selection of external auditors; appointment of any judicial representative or general agent of Petrodelta; and designation of a liquidator in the event of the liquidation of Petrodelta.
relation to such production.
Benton-Vinccler has been developing the South Monagas Unit since 1992, beginning with the Uracoa Field.
Benton-Vinccler processes the
field.
Benton-Vinccler reinjects produced water from Tucupita into the aquifer to aid the natural water drive, and we utilize a portion of the associated natural gas to operate a power generation facility to supply our power needs.
plant facilities.
In 2003, Benton-Vinccler6
Customers and Market Information
Underthroughout the remaining term of the operating service agreement, allagreement. Harvest Vinccler has entered into long-term agreements for the leasing of compression and the operation and maintenance of the gas treatment and compression facilities.
Employees and Community Relations
Benton-Vinccler has a highly skilled staff of 189 local employees and four expatriates and has also formed successful and supportive relationships with local government agencies and communities.
Benton-Vinccler has invested in a Social Community Program that includes medical programs in ophthalmologic and dental care,the SMU fields as well as additional social investments includingappraisal and development of the purchase of medicinesIsleño, Temblador and medical equipment for local communities within the South Monagas Unit.
Health, Safety and Environment
Benton-Vinccler’s health, safety and environmental policy is an integral part of its business. Benton-Vinccler continually improves its policy and practices related to personnel safety, property protection and
87
environmental management.
North GubkinskoyeFinancial Condition and South Tarasovskoye, Russia (Geoilbent)
On September 25, 2003, we sold our 34 percent minority equity investment in Geoilbent to Yukos Operational Holding Limited for $69.5 million plus $5.5 million for the repaymentResults of intercompany loans and accounts receivable. SeeNote 9 – Russian Operations.
East Urengoy, Russia (Arctic Gas Company)
Arctic Gas Company was sold in April 2002. SeeNote 9 – Russian Operations.
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 (“2007. While no assurance can be given, we believe we will continue to receive contract extensions so long as the California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. All capitalized costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the onshore property for sale.
border disputes persist.
98
Other | Total | |||||||||||||||||||
(in thousands) | Venezuela | Foreign | Foreign | United States | Total | |||||||||||||||
Year ended December 31, 2003 | ||||||||||||||||||||
Oil and gas sales | $ | 106,095 | $ | 106,095 | $ | 106,095 | ||||||||||||||
Total Assets | $ | 241,855 | $ | 237 | $ | 242,092 | $ | 132,256 | $ | 374,348 | ||||||||||
Year ended December 31, 2002 | ||||||||||||||||||||
Oil sales | $ | 126,731 | $ | 126,731 | $ | 126,731 | ||||||||||||||
Total Assets | $ | 209,733 | $ | 52,302 | $ | 262,035 | $ | 73,157 | $ | 335,192 | ||||||||||
Year ended December 31, 2001 | ||||||||||||||||||||
Oil sales | $ | 122,386 | $ | 122,386 | $ | 122,386 | ||||||||||||||
Total Assets | $ | 167,671 | $ | 100,801 | $ | 268,472 | $ | 79,679 | $ | 348,151 |
Reserves
Estimates of our Proved Reserves as of December 31, 2003 and 2002 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. The following table sets forth information regarding estimates of Proved Reserves at December 31, 2003. The Venezuelan information includes reserve information net of a 20 percent deduction for the minority interest in Benton-Vinccler. All Venezuelan reserves are attributable to an operating service agreement between Benton-Vinccler and PDVSA under which all mineral rights are owned by the Government of Venezuela.
Net Crude Oil and Condensate (MBbls) | ||||||||||||
Proved | Proved | |||||||||||
Developed | Undeveloped | Total | ||||||||||
Venezuela | 36,688 | 33,610 | 70,298 | |||||||||
(in thousands) | Venezuela | United States | Total | |||||||||
Year ended December 31, 2006 | ||||||||||||
Oil and natural gas sales | $ | 59,506 | — | $ | 59,506 | |||||||
Total Assets | $ | 306,289 | $ | 116,422 | $ | 422,711 | ||||||
Year ended December 31, 2005 | ||||||||||||
Oil and natural gas sales | $ | 236,941 | — | $ | 236,941 | |||||||
Total Assets | $ | 258,268 | $ | 142,530 | $ | 400,798 | ||||||
Year ended December 31, 2004 | ||||||||||||
Oil and natural gas sales | $ | 186,066 | — | $ | 186,066 | |||||||
Total Assets | $ | 309,794 | $ | 57,692 | $ | 367,486 |
Net Natural Gas (MMcf) | ||||||||||||
Proved | Proved | |||||||||||
Developed | Undeveloped | Total | ||||||||||
Venezuela | 84,918 | 71,482 | 156,400 | |||||||||
Estimates of commercially recoverable oil and natural gas reserves and of the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, such as:
All such estimates are to some degree speculative and various classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the commercially recoverable reserves of oil and natural gas attributable to any particular property or group of properties, the classification, cost and risk of recovering such reserves and estimates of the future net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times may vary substantially. The difficulty of making precise estimates is accentuated by the fact that 47 percent of our total Proved Reserves were undeveloped as of December 31, 2003. The cost to develop the Proved Undeveloped Reserves is expected to be $65.6 million over the next three years.
Reserve estimates are not constrained by the availability of the capital resources required to finance the estimated development and operating expenditures. In addition, actual future net cash flows will be affected by factors such as:
10
The timing of actual future net oil and natural gas sales from Proved Reserves as well as the year-end price, and thus their actual present value, can be affected by the timing of the incurrence of expenditures in connection with development of oil and gas properties. The 10 percent discount factor required by the SEC to be used to calculate present value for reporting purposes is not necessarily the most appropriate discount factor based on interest rates in effect from time to time, risks associated with the oil and natural gas industry and the political risks associated with operations in Venezuela. Discounted present value, regardless of what discount rate is used, is materially affected by assumptions as to the amount and timing of future production, which assumptions may and often do prove to be inaccurate. For the period ending December 31, 2003, we reported $545.3 million of discounted future net cash flows before income taxes from Proved Reserves based on the SEC’s required calculations.
Production, Prices and Lifting Cost Summary
Year Ended December 31, | ||||||||||||
2003 | 2002 | 2001 | ||||||||||
Venezuela | ||||||||||||
Crude Oil Production (Bbls) | 7,347,399 | 9,708,295 | 9,777,516 | |||||||||
Natural Gas Production (MMcf) | 2,660,241 | — | — | |||||||||
Average Crude Oil Sales Price ($per Bbl) | $ | 14.07 | $ | 13.08 | $ | 12.52 | ||||||
Average Natural Gas Sales Price ($per MMcf) | $ | 1.03 | — | — | ||||||||
Average Operating Expenses ($per Boe) | $ | 4.00 | $ | 3.26 | $ | 4.30 | ||||||
Russia | ||||||||||||
Geoilbent (a)(b) | ||||||||||||
Net Crude Oil Production (Bbls) | 1,913,187 | 2,349,916 | 1,762,814 | |||||||||
Average Crude Oil Sales price ($per Bbl) | $ | 14.52 | $ | 13.21 | $ | 19.51 | ||||||
Average Operating Expenses ($per Bbl) | $ | 2.83 | $ | 2.09 | $ | 2.17 | ||||||
Arctic Gas (a)(c) | ||||||||||||
Net Crude Oil Production (Bbls) | (c | ) | (c | ) | 183,087 | |||||||
Average Crude Oil Sales price ($per Bbl) | (c | ) | (c | ) | $ | 21.93 | ||||||
Average Operating Expenses ($per Bbl) | (c | ) | (c | ) | $ | 7.42 |
Year Ended December 31, | ||||||||||||
2006(a) | 2005 | 2004 | ||||||||||
Venezuela(b) | ||||||||||||
Crude Oil Production (Bbls) | 1,894,101 | 8,762,687 | 8,152,261 | |||||||||
Natural Gas Production (Mcf) | 4,506,094 | 25,677,460 | 31,059,416 | |||||||||
Average Crude Oil Sales Price ($per Bbl)(c) | $ | 28.96 | $ | 24.02 | $ | 18.90 | ||||||
Average Natural Gas Sales Price ($per Mcf) | $ | 1.03 | $ | 1.03 | $ | 1.03 | ||||||
Average Operating Expenses ($per Boe) | $ | 3.49 | $ | 3.05 | $ | 2.50 |
(a) | ||
(b) | ||
(c) |
11
Regulation
General
• | 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 | |||
• | changes in contract interpretation and policies of contract adherence. |
9
business and our potential for economic loss.
Venezuela requires environmental and other permits for certain operations conducted in oil field development, such as site construction, drilling and seismic activities. As a contractor to PDVSA, Benton-Vinccler submits capital budgets to PDVSA for approval including capital expenditures to comply with Venezuelan environmental regulations.foreseeable future.
12
Year Ended December 31, | ||||||||||||||||||||||||
2006 | 2005 | 2004 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Wells Drilled: | ||||||||||||||||||||||||
Development: | ||||||||||||||||||||||||
Crude oil | — | — | 1 | 0.8 | 16 | 12.8 | ||||||||||||||||||
Average Depth of Wells (Feet) | — | — | — | 4,349 | — | 5,443 | ||||||||||||||||||
Producing Wells(1): | ||||||||||||||||||||||||
Crude Oil | 103 | 82.4 | 108 | 86.4 | 124 | 99.2 |
Year Ended December 31, | ||||||||||||||||||||||||
2003 | 2002 | 2001 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Wells Drilled: | ||||||||||||||||||||||||
Exploration: | ||||||||||||||||||||||||
Dry hole | — | — | 1 | 0.4 | — | — | ||||||||||||||||||
Development: | ||||||||||||||||||||||||
Crude oil | 3 | 2.4 | 17 | 10.8 | 20 | 10.5 | ||||||||||||||||||
Total | 3 | 2.4 | 18 | 11.2 | 20 | 10.5 | ||||||||||||||||||
Average Depth of Wells (Feet) | 6,095 | 7,341 | 6,043 | |||||||||||||||||||||
Producing Wells(1): | ||||||||||||||||||||||||
Crude Oil | 111 | 88.8 | 258 | 158.2 | 274 | 169.9 |
(1) | The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired. |
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Venezuela | 11,166 | 8,933 | 146,677 | 117,342 | ||||||||||||
China | — | — | 7,470,080 | 7,470,080 | ||||||||||||
Total | 11,166 | 8,933 | 7,616,757 | 7,587,422 | ||||||||||||
Undeveloped | ||||||||
Gross | Net | |||||||
China | 7,470,080 | 7,470,080 | ||||||
Competition10
position, results of operations and cash flows.
11
Titlebeen completed on April 1, 2006, this adjustment will not occur until and unless the conversion is completed. The timing for completing the conversion to DevelopedPetrodelta is uncertain. While we continue to maintain cash reserves, our operations in Venezuela represent all of our revenues, and Undeveloped Acreage
All Venezuelanthe funds available to pursue our growth strategy may be adversely affected by the financial demands of continued operations in Venezuela during the conversion process.
12
• | 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
14
15
• | unexpected drilling conditions; | ||
• | pressure or irregularities in formations; | ||
• | equipment failures or accidents; | ||
• | weather conditions; | ||
• | shortages in experienced labor; | ||
• | delays in receiving necessary governmental permits; | ||
• | shortages or delays in the delivery of equipment; | ||
• | delays in receipt of permits or access to lands; and | ||
• | government actions or changes in regulations. |
16
17
1. | Proposal to approve the proposed transaction, including the conversion contract between our subsidiary Harvest Vinccler, S.C.A. and Corporación Venezolana del Petroleo, S.A., and entailing the transfer of substantially all of our assets to Empresa Mixta Petrodelta, S.A., pursuant to the conversion contract: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
30,910,607 | 133,118 | 114,731 |
2. | Proposal to postpone or adjourn the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the time of the special meeting to approve the transaction described in proposal 1: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
27,746,888 | 3,282,231 | 129,337 |
3. | To vote on such other matters as may properly come before the special meeting or any adjournment or postponement of the special meeting: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
18,457,926 | 10,894,377 | 1,806,153 |
None.
1418
We face significant risks in Venezuela. These risks and other risk factors are discussed inItem 5. Market1A – Risk FactorsandItem 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our Common Stocklies within an area which is tradedthe subject of a border dispute between the People’s Republic of China and Vietnam. Vietnam has executed an agreement on a portion of the same offshore acreage with another company. The border dispute has lasted for many years, and there has been limited exploration and no development activity in the WAB-21 area due to the dispute.
Year | Quarter | High | Low | |||||||
2002 | ||||||||||
First quarter | 4.03 | 1.43 | ||||||||
Second quarter | 5.00 | 3.77 | ||||||||
Third quarter | 5.43 | 3.21 | ||||||||
Fourth quarter | 7.54 | 5.50 | ||||||||
2003 | ||||||||||
First quarter | 6.58 | 4.40 | ||||||||
Second quarter | 6.90 | 4.20 | ||||||||
Third quarter | 7.17 | 5.58 | ||||||||
Fourth quarter | 10.02 | 6.35 |
On March 1, 2004, the last sales price for the common stock as reported by the NYSE was $11.68 per share.
Our policy is to retain earnings to support the growth of our business. Accordingly, our board of directors has never declared a cash dividend on our common stock and our indenture currently restricts the declaration and payment of any cash dividends.
Item 6. Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth our selected consolidated financial data for each of the years in the five-year period ended December 31, 2003. The selected consolidated financial data have been derived from and should be read in conjunction with our annual audited consolidated financial statements, including the notes thereto. Our year-end financial information contains results from our Russian operations through our equity affiliates based on a twelve-month period ending September 30. Accordingly, our results of operations for the years ended December 31, 2003, 2002, 2001, 2000 and 1999 reflect results from Geoilbent (until sold on September 25, 2003) for the twelve months ended September 30, 2002, 2001, 2000 and 1999, and from Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2001, 2000 and 1999.
158
Year Ended December 31, | ||||||||||||||||||||
2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||
Statement of Operations: | ||||||||||||||||||||
Total revenues | $ | 106,095 | $ | 126,731 | $ | 122,386 | $ | 140,284 | $ | 89,060 | ||||||||||
Operating income (loss) | 33,627 | 34,585 | 28,201 | 53,204 | (22,525 | ) | ||||||||||||||
Net income (loss) | 27,303 | 100,362 | 43,237 | 20,488 | (32,284 | ) | ||||||||||||||
Net income (loss) per common share: | ||||||||||||||||||||
Basic | $ | 0.77 | $ | 2.90 | $ | 1.27 | $ | 0.67 | $ | (1.09 | ) | |||||||||
Diluted | $ | 0.74 | $ | 2.78 | $ | 1.27 | $ | 0.66 | $ | (1.09 | ) | |||||||||
Weighted average common shares outstanding Basic | 35,332 | 34,637 | 33,937 | 30,724 | 29,577 | |||||||||||||||
Diluted | 36,840 | 36,130 | 34,008 | 30,890 | 29,577 |
(in thousands) | Venezuela | United States | Total | |||||||||
Year ended December 31, 2006 | ||||||||||||
Oil and natural gas sales | $ | 59,506 | — | $ | 59,506 | |||||||
Total Assets | $ | 306,289 | $ | 116,422 | $ | 422,711 | ||||||
Year ended December 31, 2005 | ||||||||||||
Oil and natural gas sales | $ | 236,941 | — | $ | 236,941 | |||||||
Total Assets | $ | 258,268 | $ | 142,530 | $ | 400,798 | ||||||
Year ended December 31, 2004 | ||||||||||||
Oil and natural gas sales | $ | 186,066 | — | $ | 186,066 | |||||||
Total Assets | $ | 309,794 | $ | 57,692 | $ | 367,486 |
Year Ended December 31, | ||||||||||||||||||||
2003 | 2002 | 2001 | 2000 | 1999 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Working capital (deficit) | $ | 137,210 | $ | 97,001 | $ | (586 | ) | $ | 12,370 | $ | 32,093 | |||||||||
Total assets | 374,348 | 335,192 | 348,151 | 286,447 | 276,311 | |||||||||||||||
Long-term debt, net of current maturities | 96,833 | 104,700 | 221,583 | 213,000 | 264,575 | |||||||||||||||
Stockholders’ equity (deficit)(1) | 199,713 | 171,317 | 67,623 | 12,904 | (17,178 | ) |
Year Ended December 31, | ||||||||||||
2006(a) | 2005 | 2004 | ||||||||||
Venezuela(b) | ||||||||||||
Crude Oil Production (Bbls) | 1,894,101 | 8,762,687 | 8,152,261 | |||||||||
Natural Gas Production (Mcf) | 4,506,094 | 25,677,460 | 31,059,416 | |||||||||
Average Crude Oil Sales Price ($per Bbl)(c) | $ | 28.96 | $ | 24.02 | $ | 18.90 | ||||||
Average Natural Gas Sales Price ($per Mcf) | $ | 1.03 | $ | 1.03 | $ | 1.03 | ||||||
Average Operating Expenses ($per Boe) | $ | 3.49 | $ | 3.05 | $ | 2.50 |
(a) | Reflects oil and natural gas deliveries through March 31, 2006. | |
(b) | Information represents 100 percent of production. | |
(c) | Average crude oil sales price after hedging activity. |
• | change in governments; | ||
• | civil unrest; | ||
• | price and currency controls; | ||
• | limitations on oil and natural gas production; | ||
• | tax, environmental, safety and other laws relating to the petroleum industry; | ||
• | changes in laws relating to the petroleum industry; | ||
• | changes in administrative regulations and the interpretation and application of such rules and regulations; and | ||
• | changes in contract interpretation and policies of contract adherence. |
9
Year Ended December 31, | ||||||||||||||||||||||||
2006 | 2005 | 2004 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Wells Drilled: | ||||||||||||||||||||||||
Development: | ||||||||||||||||||||||||
Crude oil | — | — | 1 | 0.8 | 16 | 12.8 | ||||||||||||||||||
Average Depth of Wells (Feet) | — | — | — | 4,349 | — | 5,443 | ||||||||||||||||||
Producing Wells(1): | ||||||||||||||||||||||||
Crude Oil | 103 | 82.4 | 108 | 86.4 | 124 | 99.2 |
(1) |
Undeveloped | ||||||||
Gross | Net | |||||||
China | 7,470,080 | 7,470,080 | ||||||
10
There are ongoing efforts by opponents of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of the changes and the possible politicalization of PDVSA cannot be predicted, it could adversely affect PDVSA’s ability to manage its contracts and meet its obligations with its suppliers and vendors, such as Benton-Vinccler. Organizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing of those acquisitions. While we have substantial cash reserves to withstand a future
16
disruption of sales, a prolonged loss of sales or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition.
We have been required to curtail sales to PDVSA in April and December 2002 due to insufficient crude oil storage capacity. While these appear to be isolated incidents, we cannot be assured that our sales to PDVSA will not be curtailed in the future in the same manner.
Our strategy to focus on Russia carries operating, financial, legal and political risk.While we believe our established presence in Russia and our experience and skills from prior operations positions us well for future projects, doing business in Russia also carries unique risks. The operating environment is often difficult, and the ability to operate successfully will depend onVenezuelan government. An arbitration proceeding may take a number of factors, including our abilityyears to controlconclude and we can provide no assurances as to outcome.
Acquiring new projects in Venezuela depends upon our ability to meet the requirements of the Organic Hydrocarbon Law.New oil projects in Venezuela are governed by the Organic Hydrocarbon Law which requires that such projectsConversion Contract, certain conditions must be carried out through incorporated joint ventures with majority ownership by governmental entities. While we believe it is possible to comply with the Organic Hydrocarbons Law and at the same time meet our criteria for new projects, no precedents exist and there is a risk we will be unable to achieve the desired result.
Operations in areas outside the U.S. are subject to various risks inherent in foreign operations, and our strategy to focus on Venezuela and Russia limits our country risk diversification.Our operations in areas outside the U.S. are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and the possibility of having to be subject to exclusive jurisdiction of courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States. Our strategy to focus on Venezuela and Russia concentrates our foreign operations risk and increases the potential impact to us of the operating, financial and political risks in those countries.
11Our foreign operations expose us to foreign currency risk.Presently, our only operations are located in Venezuela. Venezuela has historically been considered a highly inflationary economy. Results of operations in that country are measured in U.S. dollars, and all currency gains or losses recorded in the consolidated statement of operations. There are many factors which affect foreign exchange rates and resulting exchange gains and losses, manysatisfied, most of which are beyond our influence. We havecontrol. These conditions include approval by the Venezuelan Ministry of Energy and Petroleum (“MEP”) and the Venezuelan National Assembly; obtaining or filing all necessary consents, authorizations, orders or approvals of governmental authorities; making all necessary filings or registrations with governmental authorities and giving all requisite notifications to governmental authorities; completion of the Conversion Contract and all annexes, including the
The lossPetrodelta.Upon conversion of key personnel could adversely affectthe OSA to Petrodelta and transfer of our assets to Petrodelta, we will be a minority interest owner and no longer have sole control over operations. Our control of Petrodelta will be limited to our rights under the Conversion Contract and its annexes and the Charter and By-Laws of Petrodelta. As a result, our ability to successfully execute our strategy.We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to executeimplement our business strategy. Lossplan, assure quality control, and set the timing and pace of one or more key individualsdevelopment may be adversely affected.
Leverage materially affectsassets and acquire additional properties may be limited.We continue to look at alternatives to diversify our operations. Asassets. However, the alternatives are limited. If the conversion to Petrodelta is completed, and we decide to enter into a sale or exchange of December 31, 2003, our long-term debt was $96.8 million. Our long-term debt represented 33 percentall or part of our total capitalization at December 31, 2003. Our current
17
cash balances are in excessVenezuelan assets with an unrelated third party, the third party must be approved by the Venezuelan government. The number of these obligationspotential buyers that will be acceptable to the Venezuelan government may be limited, and lessen the impactthis number of potential buyers may be further affected and limited by country risk concerns. Further, a sale or exchange of all or part of our debt but our long-term debt can effect our operations in several important ways, includingVenezuelan assets after completing the following:
conversion to Petrodelta may be subject to U.S. federal tax consequences.
12
Failure by us to meet a capital requirement could be a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta. In addition, CVP may be unable or unwilling to fund its share of capital requirements and our ability to require them to do so is limited.
We may not be able to investunder the net cash proceeds from the sale of Geoilbent in new oil and gas projects. The terms of the 2007 Notes require that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the sale, or any amount not so invested must be used to repay or prepay the 2007 Notes or certain debts of subsidiaries.
Conversion Contract.
• | relatively minor changes in the global supply | ||
• | export quotas; | ||
• | market uncertainty; | ||
• | the level of consumer product demand; | ||
• | weather conditions; | ||
• | domestic and foreign governmental | ||
• | the price and availability of alternative fuels; | ||
• | political and economic conditions in oil-producing and oil consuming countries; and | ||
• | overall economic conditions. |
13
14
18
plusfluctuations in the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amountrelationship of the excessBolivar to earnings. Thisthe U.S. Dollar. It is called a “ceiling limitation write-down”. This charge does not impact cash flow from operating activities, but does reduce stockholders’ equity.possible to predict the extent to which we may be affected by future changes in exchange rates. The risk that we will be required to write down the carrying valuemajority of our oilVenezuelan receipts are denominated in U.S. Dollars. A large portion of our operating and gas properties increases when oilcapital expenditures are in U.S. Dollars. For a discussion of currency controls in Venezuela, seeItem 7 – Management’s Discussion and natural gas prices are low or volatile. In addition, write-downsAnalysis of Financial Condition and Results of Operations – Capital Resources.Successful acquisition of projects in any international country may occur if we experience substantial downward adjustmentsalso expose us to our estimated proved reserves. The consolidated financial statements of the wholly-owned and majority owned subsidiaries do not include ceiling test write-downsforeign currency risk in 2003. Equity in Net Losses of Affiliated Companies includes a $32.3 million (our share) ceiling test write-down recorded by Geoilbent during their fiscal year ending September 30, 2003.
that country.
Until we complete the conversion to Petrodelta, we will not have reserves to report under SEC guidelines and, accordingly, no reserves are reported as of December 31, 2006. Moreover, our quantities of proved reserves in 2005 were reduced to remove undeveloped reserves because the actions taken by the Venezuelan government created uncertainty as to whether these reserves would be recovered under the economic and operating conditions which existed in Venezuela (“Contractually Restricted Reserves”).
15
At December 31, 2003, approximately 47 percent of our estimated Proved Reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The estimates of our future reserves include the assumption that we will make significant capital expenditures to develop these reserves. Although we have prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. SeeSupplemental Information on Oil and Natural Gas Producing Activities.
19
• | unexpected drilling conditions; | ||
• | pressure or irregularities in formations; | ||
• | equipment failures or accidents; | ||
• | weather conditions; | ||
• | shortages in experienced labor; | ||
• | delays in receiving necessary governmental permits; | ||
• | shortages or delays in the delivery of equipment; | ||
• | delays in receipt of permits or access to | ||
• | government actions or changes in regulations. |
16
2003 Financial and Operational Performance
In 2003, we strengthened our management team and board of directors, added to our financial flexibility by completing the sale of Geoilbent for $69.5 million in cash plus $5.5 million for repayment of our intercompany debt and accounts receivable, added a gas revenue stream and advanced our growth plan by announcing an agreement with PDVSA to study two oil and gas fields close to our facilities in Venezuela.
At December 31, 2003, we had $138.7 million of cash and a debt to total capitalization ratio of 33 percent compared with 38 percent at the end of 2002.
20
Our board of directors has authorized the repurchase of up to one million shares of our common stock. In March 2003 we repurchased approximately 80,000 shares for an aggregate price of $0.4 million.
2004 Capital Program
Benton-Vinccler’s capital expenditures for 2004 are projected to be $30-35 million, compared with 2003 capital expenditures of $58.1 million.
In 2003, we completed our three well Bombal Field development program in Venezuela and constructed a pipeline from Bombal to the Tucupita delivery line. The Bombal drilling program delivered disappointing results. Instead of initial flush production with little or no water, the wells experienced early water breakthrough and consequently lower oil production. Benton-Vinccler converted two gas injection wells in Uracoa to gas production and completed the gas project and facilities improvements on time at a cost of $27 million.
Results of Operations
We include the results of operations of Benton-Vinccler in our consolidated financial statements and reflect the 20 percent ownership interest of Vinccler as a minority interest. We accounted for our investments in Geoilbent and Arctic Gas using the equity method. We include Geoilbent and Arctic Gas in our consolidated financial statements based on a fiscal year ending September 30. Our results of operations for the years ended December 31, 2003, 2002 and 2001 reflect the results of Geoilbent (until sold on September 25, 2003) and Arctic Gas (until sold on April 12, 2002) for the twelve months ended September 30, 2003, 2002 and 2001.
You should read the following discussion of the results of operations for each of the years in the three-year period ended December 31, 2003 and the financial condition as of December 31, 2003 and 2002 in conjunction with our Consolidated Financial Statements and related Notes thereto.
We have presented selected expense items from our consolidated income statement as a percentage of revenue in the following table:
Years Ended December 31, | ||||||||||||
2003 | 2002 | 2001 | ||||||||||
Operating Expenses | 29 | % | 27 | % | 35 | % | ||||||
Depletion, Depreciation and Amortization | 20 | 21 | 21 | |||||||||
General and Administrative | 15 | 13 | 16 | |||||||||
Taxes Other Than on Income | 3 | 3 | 4 | |||||||||
Interest | 10 | 13 | 20 |
Years ended December 31, 2003 and 2002
Net income for the year ended 2003 was $27.3 million, or $0.74 per diluted share, compared with $100.4 million for the year ended 2002. The $27.3 million net income included the gain from the sale of our minority equity investment in Geoilbent of $46.6 million, $0.4 million partial recovery of a bad debt and $1.5 million arbitration settlement related to A. E. Benton (SeeNote 13 – Related Party Transactions). Operating and general and administrative expenses were reduced by $3.8 million, or almost 8 percent, compared with 2002.
Our results of operations for the year 2003 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted for all of our production and oil and gas sales revenue. Oil revenue per barrel increased 8 percent (from $13.05 in 2002 to $14.07 in 2003) and oil sales quantities decreased 24 percent (from 9.7 MBbl of oil in 2002 to 7.3 MBbl of oil in 2003) during the year ended 2003 compared with 2002. Gas sales began on November 25, 2003, at the contract rate of $1.03 per Mcf. Incremental Crude Oil sales began on the same date at a fixed price of $7.00 per barrel. Total gas sales were 2.7 Bcf for the period.
Our revenues decreased $20.6 million, or 16 percent, during the year ended 2003 compared with 2002. This was primarily due to lower production offset by higher world crude oil prices. Our sales quantities for the year ended
21
2003 from Venezuela were 7.8 MBoe compared with 9.7 MBoe in 2002. The decrease in sales quantities of 1.9 MBoe, or 20 percent, was due to the Venezuelan national civil work stoppage which led to the shut-in of our production from December 2002 to February 2003, natural reservoir decline rates and the fact that some wells did not immediately return to previous production levels following the national work stoppage.
Our operating expenses decreased $3.1 million, or 9 percent, for the year ended 2003 compared with 2002. This was primarily due to lower production volumes partially offset by higher workover and maintenance programs that continued during the Venezuelan national civil work stoppage. Depletion, depreciation and amortization decreased $5.2 million, or 20 percent, during the year 2003 compared with 2002 primarily due to decreased production from Venezuela and the addition of natural gas reserves in 2002. Depletion expense per barrel of oil produced from Venezuela during 2003 was $2.52 compared with $2.56 during 2002 primarily due to reduced future development costs. We recognized write-downs of $0.2 million for additional capitalized costs associated with former exploration projects during the year ended 2003 compared with $13.4 million for the impairment of the China WAB-21 block and $1.1 million for the Lakeside Prospect exploration activities during the year ended 2002. General and administrative expenses decreased $0.8 million from 2002 to 2003. An arbitration settlement of $1.5 million and a bad debt recovery of $0.4 million were recorded in the third quarter of 2003, and a bad debt recovery of $3.3 million was recorded in the third quarter of 2002 related to A. E. Benton.
Taxes other than on income decreased $0.7 million, or 17 percent, during the year ended 2003 compared with 2002. This was primarily due to decreased Venezuelan municipal taxes which are a function of oil revenues partially offset by a one-time adjustment of U.S. employment taxes of $0.7 million in 2002.
Investment income and other decreased $0.7 million, or 32 percent, during the year ended 2003 compared with 2002. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $5.9 million, or 36 percent, during the year ended 2003 compared with 2002 due to lower average outstanding debt balances for the year ended 2003 compared to 2002. In 2002, we redeemed all $108 million of our 11.625 percent Senior Notes due in May 2003 and purchased $20 million face of the 9.375 percent Senior Notes due in November 2007. In October 2002, we borrowed $15.5 million to finance the construction of the gas pipeline in Venezuela from the Uracoa field to the PDVSA sales line, and we repaid all Bolivar denominated debt in March 2003.
Net gain on exchange rates decreased $4.0 million, or 88 percent, for the year ended 2003 compared with 2002. This was due to the significant devaluation of the Bolivar and Bolivar currency controls imposed in February 2003 which fixed the exchange rate between the Bolivar and the U.S. dollar and restricts the ability to exchange Venezuelan Bolivars for dollars and vice versa. We realized income before income taxes and minority interest of $71.8 million during the year 2003 compared with income of $169.8 million in the year ended 2002. The decrease was primarily attributable to the Arctic Gas Sale in 2002 offset by the sale of our minority equity investment in Geoilbent in 2003. Income tax expense decreased $50.6 million due to lower pre-tax income. The effective tax rate decreased from 36 to 13 percent for the year ended 2003 compared with 2002. The rate decrease was due to an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the benefit was fully reserved in historical periods. The income before minority interests decreased $47.4 million for the year ended 2003 compared with 2002. This decrease was due to the sale of our minority equity investment in Geoilbent partially offset by decreased production of Benton-Vinccler.
Equity in net losses of affiliated companies decreased $29.0 million during the year 2003 from $0.2 million in 2002 to a loss of $28.9 million in 2003. This was primarily due to full cost ceiling test writedowns of $32.3 million (our share) and decreased income from Geoilbent. SeeNote 9 – Russian Operations. The year ended 2002 included a loss of $1.5 million on Arctic Gas.
Years ended December 31, 2002 and 2001
Net income for the year ended 2002 was $100.4 million, or $2.78 per diluted share, compared with $43.2 million for 2001. The $100.4 million net income included the after-tax gain from the Arctic Gas Sale of $93.6 million, and the pre-tax $3.3 million, partial recovery of a bad debt related to A. E. Benton (SeeNote 13 – Related Party Transactions); offset, in part, by a pre-tax $13.4 million impairment of the WAB-21 petroleum property located in the South China Sea. Operating and general and administrative expenses were reduced by $12 million, or almost 20 percent, compared with 2001.
22
Our results of operations for the year ended 2002 primarily reflected the results for Benton-Vinccler in Venezuela, which accounted for all of our production and oil sales revenue. As a result of increases in world crude oil prices, partially offset by lower production from the South Monagas Unit, oil sales in Venezuela were 3.8 percent higher in 2002 compared with 2001. Realized fees per barrel increased 4.5 percent (from $12.52 in 2001 to $13.08 in 2002).
Our revenues increased $4.6 million, or 3.6 percent, during the year ended 2002 compared with 2001. This was due to increased oil sales revenue in Venezuela as a result of increases in world crude oil prices, partially offset by lower sales quantities. Our sales quantities for the year ended 2002 from Venezuela were 9.7 MMBbls compared to 9.8 MMBbls for the year ended 2001. The decrease in sales quantities of 100,000 Bbls, or less than 1 percent, was due primarily to logistics and equipment delays in early 2002 at the Tucupita field and the Venezuelan national civil work stoppage which led to the shut-in of our production in late December 2002 for nine days. Average production for the year decreased by less than 775 Bbls per day for the aforementioned reasons.
Our operating expenses decreased $8.8 million, or 21 percent, for the year ended 2002 compared with the year ended 2001. Lower fuel gas, water and oil treatments accounted for $3.4 million of the reduction. Reduced workover expense ($2.6 million) and lower expenses associated with the transportation of Tucupita oil ($5.0 million) with the completion of the Tucupita oil pipeline in late 2001 were offset by $1.1 million of increases in various other categories. Depletion, depreciation and amortization increased $0.8 million, or 4 percent, during the year ended 2002 compared with 2001 primarily due to the first three quarters of 2002 having been calculated on the lower beginning of the year reserves. Depletion expense per barrel of oil produced from Venezuela during 2002 was $2.56 compared with $2.26 during 2001 primarily due to future development costs. We recognized write-downs of capitalized costs of $13.4 million associated with WAB-21 offshore China and $1.1 million for the Lakeside Prospect exploration activities during the year ended 2002 compared with $0.5 million associated with final costs associated with prior exploration activities. General and administrative expenses decreased $3.6 million from 2001 to 2002. The move to Houston was completed in 2001 and overall staff levels were reduced to the current level of ten in Houston. We recognized $3.3 million of income for the partial recovery of prior year bad debt allowance for the funds received from the A.E. Benton bankruptcy. The consideration includes 600,000 shares of stock taken into treasury at a price of $3.56 per share and approximately $1.1 million in cash.
Taxes other than on income decreased $1.3 million, or 24 percent, during the year ended 2002 compared with 2001. This was primarily due to decreased Venezuelan municipal taxes and a one-time adjustment of U.S. employment taxes of $0.7 million.
Investment income and other decreased $1.0 million, or 33 percent, during the year ended 2002 compared with 2001. This was due to lower interest rates earned on average cash and marketable securities balances. Interest expense decreased $8.6 million, or 34 percent, during the year ended 2002 compared with 2001. We redeemed all $108 million of our 11.625 percent Senior Notes due in May 2003 and purchased $20 million face of the 9.375 percent Senior Notes due in November 2007. In October 2002, we borrowed $15.5 million to finance the construction of the gas pipeline in Venezuela from the Uracoa field to the PDVSA sales line.
Net gain on exchange rates increased $3.8 million, or 493 percent for the year ended 2002 compared with 2001. This was due to the significant devaluation of the Bolivar. We realized income before income taxes and minority interest of $169.8 million during the year ended 2002 compared with $7.2 million in 2001. The increase was dominated by the Arctic Gas Sale. The 2001 income tax benefit related to the potential utilization by the Arctic Gas Sale of net operating loss carry forwards in 2002. Income tax expense decreased $105.0 million due to the reversal of a substantial portion of the valuation allowance on U.S. net operation loss carryforwards in 2001. The effective tax rate in 2002 of 36 percent reflects foreign income taxes incurred on profitable foreign operations and an increase in U.S. income with no corresponding U.S. taxes because they were offset by U.S. operating loss carryforwards for which the benefit was fully reserved in historical periods. The income before minority interests increased $3.8 million for the year ended 2002 compared with 2001. This was primarily due to the increased profitability (oil prices) and reduced expenses of Benton-Vinccler.
Equity in net earnings of affiliated companies decreased $5.7 million, during the year ended 2002 compared with 2001. This was primarily due to the decreased income from Geoilbent and the elimination of Arctic Gas equity income on April 12, 2002, the date of its sale.
23
Capital Resources and Liquidity
The oil and natural gas industry is a highly capital intensive and cyclical business with unique operating and financial risks (see Risk Factors). We require capital principally to service our debt and to fund the following costs:
The amount of available capital will affect the scope of our operations and the rate of our growth. We began selling Venezuelan natural gas in November 2003, but our future rate of growth also depends substantially upon the prevailing prices of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to service our debt.
On February 5, 2003, the Government of Venezuela fixed the exchange rate between the Bolivar and the U.S. dollar, and restricted the ability to exchange Venezuelan Bolivars for U.S. dollars and vice versa. Initially the exchange rate was fixed at 1,600 Venezuelan Bolivars for each U.S. dollar. On February 6, 2004, the official exchange rate was adjusted to 1,920 Venezuelan Bolivars for each U.S. dollar. Oil companies, such as Benton-Vinccler are allowed to receive payments for oil sales in U.S. dollars and pay U.S. dollar-denominated expenses from those payments. The full amount of the Bolivar denominated debt was repaid as of March 31, 2003. As of March 1, 2004, we have cash reserves of approximately $156.0 million and do not expect the currency conversion restriction tokey personnel could adversely affect our ability to meetsuccessfully execute our short-term loan obligations.
Our abilitystrategy.We are a small organization and depend on the skills and experience of a few individuals in key management and operating positions to pay interest onexecute our debtbusiness strategy. Loss of one or more key individuals in the organization could hamper or delay achieving our strategy.
17
Debt Reduction.We currentlywe have a significant debt principal obligation payablesubstantial basis for our positions. We are unable to estimate the amount or range of a possible loss.
1. | Proposal to approve the proposed transaction, including the conversion contract between our subsidiary Harvest Vinccler, S.C.A. and Corporación Venezolana del Petroleo, S.A., and entailing the transfer of substantially all of our assets to Empresa Mixta Petrodelta, S.A., pursuant to the conversion contract: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
30,910,607 | 133,118 | 114,731 |
2. | Proposal to postpone or adjourn the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the time of the special meeting to approve the transaction described in proposal 1: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
27,746,888 | 3,282,231 | 129,337 |
3. | To vote on such other matters as may properly come before the special meeting or any adjournment or postponement of the special meeting: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
18,457,926 | 10,894,377 | 1,806,153 |
18
8
(in thousands) | Venezuela | United States | Total | |||||||||
Year ended December 31, 2006 | ||||||||||||
Oil and natural gas sales | $ | 59,506 | — | $ | 59,506 | |||||||
Total Assets | $ | 306,289 | $ | 116,422 | $ | 422,711 | ||||||
Year ended December 31, 2005 | ||||||||||||
Oil and natural gas sales | $ | 236,941 | — | $ | 236,941 | |||||||
Total Assets | $ | 258,268 | $ | 142,530 | $ | 400,798 | ||||||
Year ended December 31, 2004 | ||||||||||||
Oil and natural gas sales | $ | 186,066 | — | $ | 186,066 | |||||||
Total Assets | $ | 309,794 | $ | 57,692 | $ | 367,486 |
Year Ended December 31, | ||||||||||||
2006(a) | 2005 | 2004 | ||||||||||
Venezuela(b) | ||||||||||||
Crude Oil Production (Bbls) | 1,894,101 | 8,762,687 | 8,152,261 | |||||||||
Natural Gas Production (Mcf) | 4,506,094 | 25,677,460 | 31,059,416 | |||||||||
Average Crude Oil Sales Price ($per Bbl)(c) | $ | 28.96 | $ | 24.02 | $ | 18.90 | ||||||
Average Natural Gas Sales Price ($per Mcf) | $ | 1.03 | $ | 1.03 | $ | 1.03 | ||||||
Average Operating Expenses ($per Boe) | $ | 3.49 | $ | 3.05 | $ | 2.50 |
(a) | Reflects oil and natural gas deliveries through March 31, 2006. | |
(b) | Information represents 100 percent of production. | |
(c) | Average crude oil sales price after hedging activity. |
• | change in governments; | ||
• | civil unrest; | ||
• | price and currency controls; | ||
• | limitations on oil and natural gas production; | ||
• | tax, environmental, safety and other laws relating to the petroleum industry; | ||
• | changes in laws relating to the petroleum industry; | ||
• | changes in administrative regulations and the interpretation and application of such rules and regulations; and | ||
• | changes in contract interpretation and policies of contract adherence. |
9
Year Ended December 31, | ||||||||||||||||||||||||
2006 | 2005 | 2004 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Wells Drilled: | ||||||||||||||||||||||||
Development: | ||||||||||||||||||||||||
Crude oil | — | — | 1 | 0.8 | 16 | 12.8 | ||||||||||||||||||
Average Depth of Wells (Feet) | — | — | — | 4,349 | — | 5,443 | ||||||||||||||||||
Producing Wells(1): | ||||||||||||||||||||||||
Crude Oil | 103 | 82.4 | 108 | 86.4 | 124 | 99.2 |
(1) | The information related to producing wells reflects wells we drilled, wells we participated in drilling and producing wells we acquired. |
Undeveloped | ||||||||
Gross | Net | |||||||
China | 7,470,080 | 7,470,080 | ||||||
10
11
12
• | 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
14
15
• | unexpected drilling conditions; | ||
• | pressure or irregularities in formations; | ||
• | equipment failures or accidents; | ||
• | weather conditions; | ||
• | shortages in experienced labor; | ||
• | delays in receiving necessary governmental permits; | ||
• | shortages or delays in the delivery of equipment; | ||
• | delays in receipt of permits or access to lands; and | ||
• | government actions or changes in regulations. |
16
17
1. | Proposal to approve the proposed transaction, including the conversion contract between our subsidiary Harvest Vinccler, S.C.A. and Corporación Venezolana del Petroleo, S.A., and entailing the transfer of substantially all of our assets to Empresa Mixta Petrodelta, S.A., pursuant to the conversion contract: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
30,910,607 | 133,118 | 114,731 |
2. | Proposal to postpone or adjourn the special meeting, if necessary, to permit further solicitation of proxies if there are not sufficient votes at the time of the special meeting to approve the transaction described in proposal 1: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
27,746,888 | 3,282,231 | 129,337 |
3. | To vote on such other matters as may properly come before the special meeting or any adjournment or postponement of the special meeting: |
Against/Withheld | Abstentions/Broker Non- | |||
Votes in Favor | Votes | Votes | ||
18,457,926 | 10,894,377 | 1,806,153 |
18
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Year | Quarter | High | Low | |||||||||
2005 | First quarter | $ | 16.92 | $ | 11.30 | |||||||
Second quarter | 12.48 | 8.13 | ||||||||||
Third quarter | 11.68 | 9.00 | ||||||||||
Fourth quarter | 10.81 | 8.57 | ||||||||||
2006 | First quarter | 10.68 | 8.00 | |||||||||
Second quarter | 14.35 | 9.89 | ||||||||||
Third quarter | 14.40 | 9.71 | ||||||||||
Fourth quarter | 11.74 | 9.81 |
19
2001 | 2002 | 2003 | 2004 | 2005 | 2006 | |||||||||||||||||||
Harvest Natural Resources, Inc. | $ | 100 | $ | 448 | $ | 691 | $ | 1,199 | $ | 617 | $ | 738 | ||||||||||||
Dow Jones US E&P Index | $ | 100 | $ | 101 | $ | 130 | $ | 183 | $ | 301 | $ | 315 | ||||||||||||
S&P 500 Index | $ | 100 | $ | 77 | $ | 97 | $ | 106 | $ | 109 | $ | 124 |
20
Year Ended December 31, | ||||||||||||||||||||
2006(1) | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||
Statement of Operations: | ||||||||||||||||||||
Total revenues | $ | 59,506 | $ | 236,941 | $ | 186,066 | $ | 106,095 | $ | 126,731 | ||||||||||
Operating income | 5,499 | 119,525 | 90,480 | 33,627 | 34,585 | |||||||||||||||
Net income (loss) | (58,562 | ) | 50,839 | 34,360 | 27,303 | 100,362 | ||||||||||||||
Net income (loss) per common share: | ||||||||||||||||||||
Basic | $ | (1.57 | ) | $ | 1.38 | $ | 0.95 | $ | 0.77 | $ | 2.90 | |||||||||
Diluted | $ | (1.57 | ) | $ | 1.32 | $ | 0.90 | $ | 0.74 | $ | 2.78 | |||||||||
Weighted average common shares outstanding | ||||||||||||||||||||
Basic | 37,225 | 36,949 | 36,128 | 35,332 | 34,637 | |||||||||||||||
Diluted | 37,225 | 38,444 | 38,122 | 36,840 | 36,130 |
Year Ended December 31, | ||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Total assets | $ | 422,711 | $ | 400,798 | $ | 367,486 | $ | 374,348 | $ | 335,192 | ||||||||||
Long-term debt, net of current maturities | 66,977 | — | — | 96,833 | 104,700 | |||||||||||||||
Stockholders’ equity(2) | 244,886 | 297,512 | 243,189 | 199,713 | 171,317 |
(1) | Activities under our OSA are reflected under the equity method of accounting effective April 1, 2006. Since such activities are subject to the completion of the conversion to Petrodelta, we have not recorded any net earnings from such activities for the nine months ended December 31, 2006. | |
(2) | No cash dividends were declared or paid during the periods presented. |
21
• | In August, the MOU was amended to provide for the addition of the Isleño, Temblador and El Salto fields to Petrodelta as additional consideration for our conversion of the OSA to Petrodelta. The addition of these fields is subject to government approval. | ||
• | In a special meeting of the stockholders in December 2006, our stockholders approved entering into the transaction contemplated by the MOU. | ||
• | Harvest Vinccler has resolved and substantially paid all of the tax claims made by the SENIAT, the Venezuelan income tax authority. We continue to believe that Harvest Vinccler has properly paid all of its taxes, but we understand that resolving the income tax issues with the SENIAT is a necessary step in the transition of Harvest Vinccler’s operations to Petrodelta. | ||
• | At the request of PDVSA, Harvest Vinccler invoiced PDVSA for $36.3 million of advanced or accrued costs incurred during the last three quarters of 2006, and $21.2 million, representing the second and third quarter advances, have been reimbursed. The fourth quarter advances of $15.1 million were invoiced to PDVSA in February 2007. | ||
• | We have provided CVP with the business plan for the Petrodelta properties. Our plan calls for the immediate resumption of the suspended development of the SMU fields as well as appraisal and development of the Isleño, Temblador and El Salto fields. We are also actively working with CVP on staffing plans for Petrodelta and have reached agreement on other elements of the Conversion Contract. |
22
Three Months Ended | Nine Months Ended | |||||||
December 31, 2006 | December 31, 2006 | |||||||
Oil production (million barrels) | 1.6 | 5.2 | ||||||
Natural gas production (billion cubic feet) | 3.6 | 11.5 | ||||||
Barrels of oil equivalent | 2.2 | 7.1 | ||||||
Cash operating costs ($millions) | 11.8 | 28.5 | ||||||
Capital expenditures ($millions) | 2.9 | 3.4 |
• | maintain financial prudence and rigorous investment criteria; | ||
• | access capital markets; | ||
• | create a diversified portfolio of large assets; | ||
• | preserve our financial flexibility; | ||
• | use our experience, skills to acquire new projects; and | ||
• | keep our organizational capabilities in line with our rate of growth. |
• | Diversify our political risk:Acquire large oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our international investment portfolio. | ||
• | Seek Operational and Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments. |
23
• | Establish a Presence Through Joint Venture Partners and the Use of Local Personnel:We seek to establish a presence in the countries and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In addition, we use local personnel to help us take advantage of local knowledge and experience and to minimize costs. In pursuing new opportunities, we will seek to enter at an early stage and find local partners in an effort to reduce our risk in any one venture. | ||
• | Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time:We are willing to agree to minimum capital expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure. | ||
• | Provide Technical Expertise:We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally. In addition to our in-house technical capabilities, in January 2007 we acquired a minority interest in a technical firm with significant experience in providing leading edge geophysical, geosciences and reservoir engineering services in many places in the world. Through this acquisition we have preferred access to these services. | ||
• | Limit Exploration Activities:While our strategy does not focus on unexplored areas, we consider appropriate exploration opportunities that have large potential scale and the ability to manage risk without significant initial cost. | ||
• | Maintain A Prudent Financial Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increase our access to debt and equity markets. |
Years Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Operating Expenses | 16 | % | 17 | % | 18 | % | ||||||
Depletion, Depreciation and Amortization | 18 | 19 | 19 | |||||||||
General and Administrative | 44 | 10 | 12 | |||||||||
Taxes Other Than on Income | 7 | 3 | 3 | |||||||||
Interest Expense | 39 | 1 | 4 |
24
Year Ended | % | |||||||||||||||
December 31, | Increase | Increase | ||||||||||||||
2006 | 2005 | (Decrease) | (Decrease) | |||||||||||||
General and administrative | $ | 26.4 | $ | 22.8 | 3.6 | 16 | % | |||||||||
Contribution to Science and Technology Fund | 3.9 | — | 3.9 | 100 | ||||||||||||
Account receivable write-off on retroactive oil price adjustment | — | 4.5 | (4.5 | ) | (100 | ) | ||||||||||
Taxes other than on income | 3.9 | 6.4 | (2.5 | ) | (39 | ) | ||||||||||
Investment income and other | (9.4 | ) | (4.2 | ) | (5.2 | ) | 124 | |||||||||
Interest expense | 23.2 | 3.4 | 19.8 | 582 | ||||||||||||
Net (gain) loss on exchange rates | 0.1 | (2.8 | ) | 2.9 | (104 | ) | ||||||||||
$ | 48.1 | $ | 30.1 | $ | 18.0 | 60 | % | |||||||||
Year Ended | % | |||||||||||||||||||
December 31, | Increase | Increase | ||||||||||||||||||
(in millions) | 2005 | 2004 | (Decrease) | (Decrease) | Increase | |||||||||||||||
Revenues | ||||||||||||||||||||
Crude oil | $ | 210.5 | $ | 154.1 | $ | 56.4 | 37 | % | ||||||||||||
Natural gas | 26.4 | 32.0 | (5.6 | ) | (18 | ) | ||||||||||||||
Total Revenues | $ | 236.9 | $ | 186.1 | $ | 50.8 | 27 | % | ||||||||||||
Price and Volume Variances | ||||||||||||||||||||
Crude oil price Variance (per Bbl) | $ | 24.02 | $ | 18.90 | $ | 5.12 | 27 | % | $ | 41.6 | ||||||||||
Volume Variances | ||||||||||||||||||||
Crude oil volumes (MBbls) | 8,763 | 8,152 | 611 | 7 | % | $ | 14.7 | |||||||||||||
Natural gas volumes (MMcf) | 25,677 | 31,059 | (5,382 | ) | (17 | ) | (5.5 | ) | ||||||||||||
Total volume variances | $ | 9.2 | ||||||||||||||||||
25
Year Ended | % | |||||||||||||||
December 31, | Increase | Increase | ||||||||||||||
2005 | 2004 | (Decrease) | (Decrease) | |||||||||||||
Operating expenses | $ | 39.7 | $ | 33.3 | $ | 6.4 | 19 | % | ||||||||
Depletion and amortization | 41.2 | 34.2 | 7.0 | 20 | ||||||||||||
Depreciation | 2.7 | 1.9 | 0.8 | 42 | ||||||||||||
General and administrative | 22.8 | 21.9 | 0.9 | 4 | ||||||||||||
Account receivable write-off on retroactive oil price adjustment | 4.5 | — | 4.5 | 100 | ||||||||||||
Gain on sale of long-lived assets | — | (0.6 | ) | 0.6 | 100 | |||||||||||
Bad debt recovery | — | (0.6 | ) | 0.6 | 100 | |||||||||||
Taxes other than on income | 6.4 | 5.6 | 0.8 | 14 | ||||||||||||
Investment income and other | (4.2 | ) | (2.1 | ) | (2.1 | ) | 100 | |||||||||
Interest expense | 3.4 | 7.7 | (4.3 | ) | (56 | ) | ||||||||||
Net (gain) loss on exchange rates | (2.8 | ) | 0.6 | (3.4 | ) | 566 | ||||||||||
$ | 113.7 | $ | 101.9 | $ | 11.8 | 12 | % | |||||||||
26
Harvest Vinccler loans. We have no other debt obligations.
Benton-Vinccler’s oil and gas pipeline project loans allow the lenderPetrodelta to accelerate repayment if production ceases for a period greater than thirty days. During the production shut-in which started in December 2002, Benton-Vinccler was granted a waiver of this provision until February 18, 2003 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reduced our net interest expense as the current interest expense was more than the current interest income earned on the invested funds. On February 8, 2003, Benton-Vinccler commenced production, thereby eliminating the need for an additional waiver. A future disruption of production could trigger the debt acceleration provision again. While no assurances can be given, we believe Benton-Vinccler would be able to obtain another waiver under acceptable terms and conditions.
declare dividends.
24
Year Ended December 31, | ||||||||||||
(in thousands) | ||||||||||||
2003 | 2002 | 2001 | ||||||||||
Net cash provided by operating activities | $ | 38,538 | $ | 42,627 | $ | 36,608 | ||||||
Net cash provided by (used in) investing activities | 38,191 | 126,143 | (48,082 | ) | ||||||||
Net cash provided by (used in) financing activities | (2,570 | ) | (113,293 | ) | 5,366 | |||||||
Net increase (decrease) in cash | $ | 74,159 | $ | 55,477 | $ | (6,108 | ) | |||||
Year Ended December 31, | ||||||||||||
(in thousands) | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Net cash provided by (used in) operating activities | $ | (24,448 | ) | $ | 114,665 | $ | 74,140 | |||||
Net cash used in investing activities | (90,556 | ) | (15,647 | ) | (39,684 | ) | ||||||
Net cash provided by (used in) financing activities | 100,064 | (20,599 | ) | (88,516 | ) | |||||||
Net increase (decrease) in cash | $ | (14,940 | ) | $ | 78,419 | $ | (54,060 | ) | ||||
Venezuela in our consolidated financial statements for the year ended December 31, 2006 and the charge in the second and third quarters 2006 of $73.8 million for additional taxes and related interest for the impact of income tax assessments by the SENIAT for 2001 through first quarter 2006.
2006 under the equity method of accounting pending conversion to Petrodelta.
The timing and sizeannual budget approved by the Petrodelta Board of capital expenditures forDirectors to implement the South Monagas Unit are entirely atbusiness plan. Outside of Venezuela, our discretion. Our remaining capital commitments worldwide support our search for new acquisitions,business development efforts and are relatively minimal and substantially at our discretion. We will also be required to make annual interest payments of approximately $8.0 million on the 2007 Notes.
27
We continue to assess production levels and commodity prices in conjunction with our capital resources and liquidity requirements.
variable rate loans).
Payments (in thousands) Due by Period | ||||||||||||||||
Less than | ||||||||||||||||
Contractual Obligation | Total | 1 Year | 1-3 Years | 3-5 Years | ||||||||||||
Long Term Debt | $ | 103,200 | $ | 6,367 | $ | 6,367 | $ | 90,466 | ||||||||
Office Lease | 88 | 88 | — | — | ||||||||||||
Total | $ | 103,288 | $ | 6,455 | $ | 6,367 | $ | 90,466 | ||||||||
While we can give no assurance, we currently believe that our cash flow from operations coupled with our cash and marketable securities on hand will provide sufficient capital resources and liquidity to fund our planned capital expenditures, investments in and advances to affiliates, and semiannual interest paymentApril 2014. In addition, Harvest Vinccler has lease obligations for the next 12 months. Our expectation is based upon our current estimate of projected prices, production levels,office space in Maturin and our assumptions that there will be no further disruptions to our productionCaracas, Venezuela for approximately $13,200 and that PDVSA will timely pay our invoices. Actual results could be materially affected if there is a significant change in our expectations or assumptions. Future cash flows are subject to a number of variables including, but not limited to, the level of production and prices, as well
25
as various economic and political conditions that have historically affected the oil and natural gas business. Additionally, prices for oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond our control.
We currently have a significant debt obligation of $85 million payable in November 2007. Our ability to meet our debt obligation and to reduce our level of debt depends on the successful implementation of our business strategy.
$4,000 per month, respectively.
Payments (in thousands) Due by Period | ||||||||||||||||||||
Less than | After 4 | |||||||||||||||||||
Contractual Obligation | Total | 1 Year | 1-2 Years | 3-4 Years | Years | |||||||||||||||
Long-Term Debt | $ | 104,651 | $ | 37,674 | $ | 38,140 | $ | 28,837 | $ | — | ||||||||||
Building Lease | 2,775 | 407 | 400 | 412 | 1,556 | |||||||||||||||
Total | $ | 107,426 | $ | 38,081 | $ | 38,540 | $ | 29,249 | $ | 1,556 | ||||||||||
Within the United States, inflation has had a minimal effect on us, but it is potentially an important factor inwith respect to results of operations in Venezuela. With respect to Benton-Vinccler, a significant majority of the sources of funds, including the proceeds from oil sales, our contributions and credit financings, are denominated in U.S. dollars, while a minor amount of local transactions in Venezuela are conducted in local currency. If the rate of increase in the value of the U.S. dollar compared with the Bolivar continues to be less than the rate of inflation in Venezuela, then inflation could be expected to have an adverse effect on Benton-Vinccler.
28
Oil and natural gas revenuePetrodelta is accrued monthly based on sales. Each quarter, Benton-Vinccler invoices PDVSA based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollar contract service fees per barrel.
completed.
The full cost method of accounting uses proved reserves in the calculation of depletion, depreciation and amortization. Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological
26
and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. A large portion of our proved reserves base from consolidated operations is comprised of oil and gas properties that are sensitive to oil price volatility. We are susceptible to significant upward and downward revisions to our Proved Reserve volumes and values as a result of changes in year end oil and gas prices and the corresponding adjustment to the projected economic life of such properties. Prices for oil and gas are likely to continue to be volatile, resulting in future revision to our Proved Reserve base. We perform a quarterly cost center ceiling test of our oil and gas properties under the full cost accounting rules of the SEC. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter and require a write–down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998 other than the write-downs recorded by our equity affiliates. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved reserves will change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.
position, results of operations or cash flows.
29
27
30majorityrisks or rewards associated with the VIE.Financial Accounting Standards Board (“FASB”) issued SFAS 157 – Fair Value Measurement (“SFAS 157”) which establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. Adoption is effective for all financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged. SFAS 157 will not have a material effect on our consolidated financial position, results of operations and cash flows.December 2003,September 2006, the FASB issued SFAS 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“SFAS 158”) which improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a revision to FIN 46, Interpretation No. 46R (“FIN 46R”), to clarify somedefined benefit postretirement plan as an asset or liability in its statement of the provisions of FIN 46,financial position and to defer certain entities from adopting untilrecognize changes in that funded status in the endyear in which the changes occur through comprehensive income. Adoption is effective as of December 31, 2006, for calendar year corporations with publicly traded equity securities. Earlier application is encouraged. SFAS 158 will not have an effect on our consolidated financial position, results of operations or cash flows.first interim or annual reporting period ending after March 15, 2004. ApplicationSEC issued Staff Accounting Bulletin No. 108 (“SAB 108”) regarding the process of FIN 46R is requiredquantifying financial statement misstatements. SAB 108 addresses the diversity in practice in quantifying financial statementsstatement misstatements and the potential under current practice for the build up of public entities thatimproper amounts on the balance sheet. The guidance in SAB 108 did not have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other typesa material effect on our consolidated financial position, results of VIEs is required in financial statements for periods ending after March 15, 2004.operations and cash flows.believe wedo not have no arrangements that would require the application of FIN 46R. We have no materialany off-balance sheet arrangements. and political risk, as discussed below.Through February 14, 2003, we utilized a costless collar hedge transaction with respect to a portion of our oil production to achieve a more predictable cash flow,In August and establish an acceptable rate of return on our Tucupita drilling program, as well as to reduce our exposure to price fluctuations. Benton-VincclerSeptember 2004, Harvest Vinccler hedged a portion of its 2003 oil productionsales for calendar year 2005 by purchasing atwo WTI crude oil “put” to protect its 2003 cash flow.puts. Because gains or losses associated with hedging transactions are included in oil sales when the hedged production is delivered, such gains and losses are generally offset by similar changes in the realized prices of the commodities. SeeNote 1 – Derivatives and Hedgingfor a complete discussion of our derivative activity. Currently, we haveWe had no hedging transactions in place for our 2004 or 2006 production.long-termshort-term debt at December 31, 20032006 of $96.8$37.7 million consisted of fixed-rate senior unsecured notes maturing in 2007 ($85.0 million). Benton-Vinccler has $11.8Harvest Vinccler’s Bolivar denominated debt, which had a fixed rate for its initial twelve months. Total short-term debt at December 31, 2005 of $5.5 million consisted of Harvest Vinccler U.S. dollarDollar denominated variable rate loans.loans, which was all repaid in 2006. A hypothetical 10 percent adverse change in the interest rate would not have a material affect on our results of operations.
For
Political Risk
Political and economic uncertainty remains very high in Venezuela. During 2003, the production from the South Monagas Unit in Venezuela represented all of our total production from consolidated companies. Our production, revenue and cash flow will be adversely affected if production from the South Monagas Unit decreases significantly for any reason. From December 14, 2002 through February 6, 2003, no sales were made because of PDVSA’s inability to accept our oil due to the national civil work stoppage in Venezuela. As a result, 2002 sales were reduced by approximately 0.6 million barrels and 2003 sales were reduced by an estimated 1.2 million barrels. As a result of the Venezuelan national civil work stoppage, the Venezuelan government terminated several thousand PDVSA employees and announced a restructuring of PDVSA’s operations. Throughout 2003, there have been numerous organizational changes in PDVSA. As a result of the situation in PDVSA, its payment to Benton-Vinccler for crude delivered in the fourth quarter of 2002 was late by seven days. However, all other payments have been on time, and we believe PDVSA is committed to building its production levels and returning to more normalized business relations with its customers and suppliers.
28
There are ongoing efforts by opponents of President Chavez for a constitutional recall referendum. A successful recall referendum could lead to new presidential elections. These events create civil unrest and the possibility of work stoppages or disruptions. The political uncertainty and economic instability in Venezuela could adversely affect our operations and business prospects in that country. In addition, while the effect of the changes and the possible politicalization of PDVSA cannot be predicted, it could adversely affect PDVSA’s ability to manage its contracts and meet its obligations with its suppliers and vendors, such as Benton-Vinccler. Organizational instability and uncertainty at PDVSA could also adversely affect our ability to acquire new projects in Venezuela and the timing of those acquisitions. While we have substantial cash reserves to withstand a future disruption of sales, a prolonged loss of sales or a failure or delay by PDVSA to pay our invoices could have a material adverse effect on our financial condition.
S-36.S-28.
31 among other things, adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant’s quarterly and annual reports under the Securities Exchange Act of 1934 (the “Exchange Act”). While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area. Our principal executive officer There have not been any changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) or 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.principalconsolidated subsidiaries, is made known to the officers who certify our financial officer have informed us that, based uponreports and to other members of senior management and the Board of Directors.2003, of2006, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and Ruleor 15d-15(e) under the Exchange Act), they have are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is 1) recorded, processed, summarized and reported within the time periods as specified in the SEC’s rules and forms and 2) accumulated and communicated to our management, including our principal executive and principal financial officers, to allow timely decisions regarding required disclosure.those disclosure controls and procedures are effective. There have been no changes in our internal controls or in other factors known to us that could significantly affect these controls subsequent to their evaluation, nor have we been required to take any corrective actions with regard to any significant deficienciescontrol over financial reporting was effective as of December 31, 2006. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006, and material weaknesses.issued an attestation report which is included herein.29
PART III
and Corporate Governanceand Executive Officers of the Registrant20042007 Annual Meeting of Shareholders.Stockholders.
20042007 Annual Meeting of Shareholders.Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 20042007 Annual Meeting of Shareholders.Stockholders.
Item 13. Certain Relationships and Related Transactions
Item 13. Certain Relationships and Related Transactions, and Director Independence 20042007 Annual Meeting of Shareholders.Stockholders.
32Accountants”Registered Public Accounting Firm” in our Proxy Statement for the 20042007 Annual Meeting of Shareholders.Stockholders.30
PART IV
33 and Reports on Form 8-KPage(a) 1.Index to Financial Statements:Report of Independent AuditorsS-1Consolidated Balance Sheets at December 31, 2003 and 2002S-2Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001S-3Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001S-4Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001S-5Notes to Consolidated Financial StatementsS-72. Consolidated Financial Statement Schedules:Schedule II - - Valuation and Qualifying AccountsSchedule III - - Financial Statements and Notes for LLC GeoilbentAll other schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.3. Exhibits: 3.1Page (a)1. Index to Financial Statements: Certificate of Incorporation filed September 9, 1988 (Incorporated by reference to Exhibit 3.1 to our Registration Statement (Registration No. 33-26333)). 3.2 Amendment to Certificate of Incorporation filed June 7, 1991 (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-39214)). 3.3 Amended and Restated Bylaws as of December 11, 2003.S-2 4.1 Form of Common Stock Certificate (Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)).S-3 S-4 S-5 S-7 3.1 Amended and Restated Certificate of Incorporation. (Incorporated by reference to Exhibit 3.1(i) to our Form 10-Q filed on August 13, 2002, File No. 1-10762.) 3.2 Amended and Restated Bylaws as of April 6, 2006. (Incorporated by reference to Exhibit 3.2 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.) 4.1 Form of Common Stock Certificate. (Incorporated by reference to the exhibits to our Registration Statement Form S-1 (Registration No. 33-26333).) 4.2 Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.) 4.3 Second Amended and Restated Rights Agreement, dated as of April 15, 2005, between Benton OilHarvest Natural Resources, Inc. and Gas Company and First InterstateWells Fargo Bank, Rights Agent dated April 28, 1995.N.A. (Incorporated by reference to Exhibit 4.14.3 to our Form 10-Q filed on August 13, 2002,April 29, 2005, File No. 1-10762.) 10.1 Form of Employment Agreements (Exhibit 10.19)(Previously filed as an exhibit to our S-1 Registration Statement (Registration No. 33-26333)).10.2 Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange Commission—Exhibit 10.25)(Previously filed as an exhibitCommission. (Incorporated by reference to the exhibits to our S-1 Registration Statement Form S-1 (Registration No. 33-52436).).31 10.3 Indenture dated November 1, 1997 between Benton Oil and Gas Company and First Trust of New York, National Association, Trustee related to an aggregate of $115,000,000 principal amount of 9 3/8 percent Senior Notes due 2007 (Incorporated by reference to Exhibit 10.1 to our Form 10-Q for the quarter ended September 30, 1997, File No. 1-10762).10.4Note payable agreement dated March 8, 2001 between Benton-Vinccler, C.A. and Banco Mercantil, C.A. related to a note in the principal amount of $6,000,000 with interest at LIBOR plus five percent, for financing of Tucupita Pipeline (Incorporated by reference to Exhibit 10.24 to our Form 10-Q, filed on May 15, 2001, File No. 1-10762).10.5Change of Control Severance Agreement effective May 4, 2001 (Incorporated by reference to Exhibit 10.26 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).10.6 Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.).
10.5 | 2001 Long Term Stock Incentive | |||||
10.6 | Addendum No. 2 to Operating | |||||
10.7† | ||||||
10.8† | Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) | |||||
10.9† | Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) | |||||
10.10† | Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) | |||||
10.11† | Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) | |||||
10.12 | The Transitory Agreement between Harvest Natural Resources, Inc. and PDVSA Petroleo S.A., dated August 4, 2005. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on | |||||
10.13 | † | Employment Agreement dated | ||||
10.14† | Employment Agreement dated | |||||
10.15† | Employment Agreement dated | |||||
10.16† | Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) | |||||
10.17† | Employment Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) | |||||
10.18† | Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) | |||||
10.19† | Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) |
34
10.20† | Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) | |||||
10.21† | Employment Agreement dated February 10, 2006 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit | |||||
10.22 | Memorandum of Understanding dated March 31, 2006, between Corporación Venezolana del Petroleo, S.A., PDVSA Petroleo, S.A. and Harvest Vinccler, C.A. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.) | |||||
10.23 | ||||||
10.24 | Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) | |||||
Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) | ||||||
10.26 | Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) | |||||
10.27 | Stock Unit Award Agreement dated September | |||||
10.28 | Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) | |||||
10.29 | Note Payable agreement dated September 28, 2006 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. Banco Universal related to a principal amount of 105 billion Bolivars with interest at 10.02 percent, for financing of the | |||||
10.30 | Note Payable agreement dated October 3, 2006 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. Banco Universal related to a principal amount of 20 billion Bolivars with interest at 10.02 percent, for financing of the SENIAT assessments. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 26, 2006, File No. 1-10762.) | |||||
10.31 |
32
10.32 | Note Payable agreement dated November 20, 2006 between Harvest Vinccler, C.A. and | |||||
10.33 | ||||||
21.1 | List of subsidiaries. |
35
23.1 | Consent of PricewaterhouseCoopers LLP | |||||
23.2 | ||||||
Consent of Ryder Scott Company, LP | ||||||
31.1 | Certification | |||||
31.2 | Certification | |||||
32.1 | ||||||
32.2 | Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer. |
† | Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K. |
36
(b) Reports on Form 8-K
On October 10, 2003, we filed a Current Report on Form 8-K disclosing the Unaudited Pro Forma results from the sale of our minority equity investment in Geoilbent.
On November 6, 2003, we filed a Current Report on Form 8-K announcing our third quarter and nine months net income and earnings.
33
REPORT OF INDEPENDENT AUDITORS
:
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Houston, Texas
March 4, 2004
S-1
S-2 December 31, 2003 2002 (in thousands, except per share data) ASSETS Current Assets: Cash and cash equivalents $ 138,660 $ 64,501 Restricted cash 12 1,812 Marketable securities — 27,388 Accounts and notes receivable: Accrued oil sales 32,766 27,359 Joint interest and other, net 11,197 8,002 Prepaid expenses and other 805 2,969 Total Current Assets 183,440 132,031 Restricted Cash 16 16 Other Assets 2,080 2,520 Deferred Income Taxes 4,749 4,082 Investments In and Advances To Affiliated Companies — 51,783 Property and Equipment: Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2003 and 2002, respectively) 593,622 576,601 Other administrative property 8,948 7,503 602,570 584,104 Accumulated depletion, depreciation, and amortization (418,507 ) (439,344 ) Net Property and Equipment 184,063 144,760 $ 374,348 $ 335,192 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities: Accounts payable, trade and other $ 4,163 $ 3,804 Accounts payable, related party 10,375 9,779 Accrued expenses 15,251 10,865 Accrued interest payable 1,427 1,405 Income taxes payable 8,647 6,880 Commodity hedging contract — 430 Current portion of long-term debt 6,367 1,867 Total Current Liabilities 46,230 35,030 Long-Term Debt 96,833 104,700 Asset Retirement Liability 1,459 — Commitments and Contingencies — — Minority Interest 30,113 24,145 Stockholders’ Equity: Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2003 and 2002; issued 36,405 shares and 35,900 shares at December 31, 2003 and 2002, respectively 364 359 Additional paid-in capital 175,051 173,559 Retained earnings 27,537 234 Treasury stock, at cost, 730 shares and 650 shares at December 31, 2003 and 2002, respectively (3,239 ) (2,835 ) Total Stockholders’ Equity 199,713 171,317 $ 374,348 $ 335,192 December 31, �� 2006 2005 (in thousands, except per share data) ASSETS Current Assets: Cash and cash equivalents $ 148,079 $ 163,019 Restricted cash 15,888 — Accounts and notes receivable: Accrued oil and gas sales — 60,900 Joint interest and other, net 9,811 10,750 Advances to provisional equity affiliate 19,146 — Deferred income tax 5,608 3,052 Prepaid expenses and other 1,246 2,149 Total Current Assets 199,778 239,870 Restricted Cash 73,001 — Other Assets 176 1,600 Investment in provisional equity affiliate 146,436 — Property and Equipment: Oil and gas properties (full cost method-costs of $2,900 excluded from amortization in 2006 and 2005, respectively) 2,900 641,684 Other administrative property 1,375 9,568 4,275 651,252 Accumulated depletion, depreciation, and amortization (955 ) (491,924 ) Net Property and Equipment 3,320 159,328 $ 422,711 $ 400,798 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities: Accounts payable, trade and other $ 3,827 $ 408 Accounts payable, related party 9,637 9,203 Accrued expenses 12,975 18,444 Accrued interest 6,850 2,637 Deferred revenue 11,217 6,728 Income taxes payable 34 18,909 Current portion of long-term debt 37,674 5,467 Total Current Liabilities 82,214 61,796 Long-Term Debt 66,977 — Asset Retirement Liability — 2,129 Commitments and Contingencies Minority Interest 28,634 39,361 Stockholders’ Equity: Preferred stock, par value $0.01 a share; Authorized 5,000 shares; outstanding, none Common stock, par value $0.01 a share; Authorized 80,000 shares at December 31, 2006 and 2005; issued 37,974 shares and 37,757 shares at December 31, 2006 and 2005, respectively 380 378 Additional paid-in capital 194,176 188,242 Retained earnings 54,174 112,736 Treasury stock, at cost, 770 shares at December 31, 2006 and 2005, respectively (3,844 ) (3,844 ) Total Stockholders’ Equity 244,886 297,512 $ 422,711 $ 400,798
AND COMPREHENSIVE INCOME S-3 Years Ended December 31, 2003 2002 2001 (in thousands, except per share data) Oil sales $ 103,920 $ 127,015 $ 122,386 Gas sales 2,740 — — Ineffective hedge activity (565 ) (284 ) — 106,095 126,731 122,386 Operating expenses 30,893 33,950 42,759 Depletion, depreciation and amortization 21,188 26,363 25,516 Write-downs of oil and gas properties and impairments 165 14,537 468 General and administrative 15,746 16,504 20,072 Arbitration settlement 1,477 — — Bad debt recovery (374 ) (3,276 ) — Taxes other than on income 3,373 4,068 5,370 72,468 92,146 94,185 Income from Operations 33,627 34,585 28,201 Other Non-Operating Income (Expense) Gain on disposition of assets 46,619 144,029 — Gain on early extinguishment of debt — 874 — Investment earnings and other 1,418 2,080 3,088 Interest expense (10,405 ) (16,310 ) (24,875 ) Net gain on exchange rates 529 4,553 768 38,161 135,226 (21,019 ) Income from Consolidated Companies Before Income Taxes and Minority Interest 71,788 169,811 7,182 Income Tax Expense (Benefit) 9,657 60,295 (35,698 ) Income Before Minority Interest 62,131 109,516 42,880 Minority Interest in Consolidated Subsidiary Companies 5,968 9,319 5,545 Income from Consolidated Companies 56,163 100,197 37,335 Equity in Net Income (Losses) of Affiliated Companies (28,860 ) 165 5,902 Net Income $ 27,303 $ 100,362 $ 43,237 Net Income Per Common Share: Basic $ 0.77 $ 2.90 $ 1.27 Diluted $ 0.74 $ 2.78 $ 1.27 Years Ended December 31, 2006 2005 2004 (in thousands, except per share data) Oil sales $ 54,858 $ 210,493 $ 154,075 Gas sales 4,648 26,448 31,991 59,506 236,941 186,066 Operating expenses 9,241 39,723 33,324 Depletion, depreciation and amortization 10,510 43,968 36,020 General and administrative 26,421 22,819 21,857 Contribution to Science and Technology Fund 3,887 — — Account receivable write-off on retroactive oil price adjustments — 4,548 — Bad debt recovery — — (598 ) Gain on sale of long-lived asset — — (578 ) Taxes other than on income 3,948 6,358 5,561 54,007 117,416 95,586 Income from Operations 5,499 119,525 90,480 Other Non-Operating Income (Expense) Loss on early extinguishment of debt — — (2,928 ) Investment earnings and other 9,406 4,205 2,085 Interest expense (23,156 ) (3,388 ) (7,749 ) Net gain (loss) on exchange rates (121 ) 2,752 (622 ) (13,871 ) 3,569 (9,214 ) Income (Loss) from Consolidated Companies Before Income Taxes and Minority Interest (8,372 ) 123,094 81,266 Income Tax Expense 60,917 57,025 33,288 Income (Loss) Before Minority Interest (69,289 ) 66,069 47,978 Minority Interest in Consolidated Subsidiary Companies (10,727 ) 15,230 13,618 Net Income (Loss) $ (58,562 ) $ 50,839 $ 34,360 Net Income (Loss) Per Common Share: Basic $ (1.57 ) $ 1.38 $ 0.95 Diluted $ (1.57 ) $ 1.32 $ 0.90 Other comprehensive loss: Unrealized mark to market loss from cash flow hedging activities, net of tax — — (487 ) Comprehensive income (loss) $ (58,562 ) $ 50,839 $ 33,873
S-4 Retained Common Additional Earnings Shares Common Paid-in (Accumulated Treasury Issued Stock Capital Deficit) Stock Total 33,872 $ 339 $ 156,629 $ (143,365 ) $ (699 ) $ 12,904 Issuance of common shares: Non-employee director compensation 292 3 471 — — 474 Tax benefits related to stock option compensation — — 11,008 — — 11,008 Net Income — — — 43,237 — 43,237 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 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 36,405 $ 364 $ 175,051 $ 27,537 $ (3,239 ) $ 199,713 Accumulated Common Additional Other Shares Common Paid-in Retained Comprehensive Treasury Issued Stock Capital Earnings Gain(Loss) Stock Total 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 37,544 375 185,183 61,897 (487 ) (3,779 ) 243,189 Issuance of common shares: Exercise of stock options 240 3 829 — — — 832 Employee stock-based compensation 74 — 2,230 — — — 2,230 Treasury stock (5 shares) — — — — — (65 ) (65 ) Accumulated other comprehensive gain — — — — 487 — 487 Net Income — — — 50,839 — — 50,839 37,858 378 188,242 112,736 — (3,844 ) 297,512 Issuance of common shares: Exercise of stock options 139 1 879 — — — 880 Employee stock-based compensation 80 1 5,055 — — — 5,056 Net Loss — — — (58,562 ) — — (58,562 ) 38,077 $ 380 $ 194,176 $ 54,174 $ — $ (3,844 ) $ 244,886
S-5 Years Ended December 31, 2003 2002 2001 (in thousands) Cash Flows From Operating Activities: Net income $ 27,303 $ 100,362 $ 43,237 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization 21,188 26,363 25,516 Write-down and impairment of oil and gas properties 165 14,537 468 Amortization of financing costs 497 1,745 1,179 Gain on disposition of assets (46,619 ) (144,029 ) (336 ) Equity in net earnings (losses) of affiliated companies 28,860 (165 ) (5,902 ) Allowance for employee notes and accounts receivable (169 ) (2,987 ) 365 Non-cash compensation related charges 296 1,458 474 Minority interest in undistributed earnings of subsidiaries 5,968 9,319 5,545 Gain from early extinguishment of debt — (874 ) — Tax benefits related to stock option compensation — — 11,008 Deferred income taxes (667 ) 53,618 (53,407 ) Changes in operating assets and liabilities: Accounts and notes receivable (7,935 ) (1,972 ) 11,756 Prepaid expenses and other 2,164 (1,130 ) 565 Accounts payable 359 (4,328 ) (4,671 ) Accounts payable, related party 4,386 (604 ) (1,662 ) Accrued interest payable 22 (2,489 ) 161 Accrued expenses (76 ) (9,686 ) 1,705 Asset retirement liability 1,459 — — Commodity hedging contract (430 ) 430 — Income taxes payable 1,767 3,059 607 Net Cash Provided by Operating Activities 38,538 42,627 36,608 Cash Flows from Investing Activities: Proceeds from sale of investment 69,500 189,841 — Additions of property and equipment (60,925 ) (43,346 ) (43,364 ) Investment in and advances to affiliated companies 2,328 9,185 (16,855 ) Increase in restricted cash — (2,800 ) (57 ) Decrease in restricted cash 1,800 1,000 10,961 Purchases of marketable securities (256,058 ) (353,478 ) (15,067 ) Maturities of marketable securities 283,446 326,090 16,370 Investment selling costs (1,900 ) (349 ) (70 ) Net Cash Provided by (Used In) Investing Activities 38,191 126,143 (48,082 ) Cash Flows from Financing Activities: Net proceeds from exercise of stock options 1,201 3,345 — Purchase of treasury stock (404 ) — — Proceeds from issuance of notes payable — 15,500 21,112 Payments on notes payable (3,367 ) (132,138 ) (15,746 ) Net Cash Provided by (Used In) Financing Activities (2,570 ) (113,293 ) 5,366 Net Increase (Decrease) in Cash and Cash Equivalents 74,159 55,477 (6,108 ) Cash and Cash Equivalents at Beginning of Year 64,501 9,024 15,132 Cash and Cash Equivalents at End of Year $ 138,660 $ 64,501 $ 9,024 Supplemental Disclosures of Cash Flow Information: Cash paid during the year for interest expense $ 13,241 $ 19,201 $ 25,721 Cash paid during the year for income taxes $ 4,254 $ 3,935 $ 3,057 Years Ended December 31, 2006 2005 2004 (in thousands) Cash Flows From Operating Activities: Net income (loss) $ (58,562 ) $ 50,839 $ 34,360 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization 10,510 43,968 36,020 Amortization of financing costs — — 228 Gain on disposition of assets and investments — — (578 ) Write off of unamortized financing costs — — 936 Account receivable write-off on retroactive oil price adjustments — 4,548 — Allowance for employee notes and accounts receivable — — (598 ) Deferred compensation expense — (745 ) 1,521 Non-cash compensation related charges 5,056 2,230 2,152 Minority interest in consolidated subsidiary companies (10,727 ) 15,230 13,618 Deferred income taxes (2,556 ) 2,982 (1,285 ) Changes in operating assets and liabilities: Accounts and notes receivable 61,839 (4,481 ) (27,156 ) Advances to provisional equity affiliate (19,146 ) — — Prepaid expenses and other 903 (723 ) (621 ) Commodity hedging contract — 14,947 (14,947 ) Accounts payable 3,419 (8,020 ) 4,265 Accounts payable, related party 434 (1,860 ) 506 Accrued expenses (5,469 ) (10,165 ) 12,765 Accrued interest 4,213 2,565 (1,356 ) Deferred revenue 4,489 6,728 — Asset retirement liability 24 188 482 Income taxes payable (18,875 ) (3,566 ) 13,828 Net Cash Provided By (Used In) Operating Activities (24,448 ) 114,665 74,140 Cash Flows from Investing Activities: Proceeds from sale of long-lived assets — — 578 Additions of property and equipment (1,657 ) (16,147 ) (39,106 ) Investments in provisional equity affiliates (513 ) — — (Increase) decrease in restricted cash (88,889 ) 28 — Investment costs 503 472 (1,156 ) Net Cash Used In Investing Activities (90,556 ) (15,647 ) (39,684 ) Cash Flows from Financing Activities: Net proceeds from issuances of common stock 880 767 7,451 Proceeds from issuance of notes payable 118,953 — — Payments of note payable (19,769 ) (6,366 ) (91,367 ) Dividend paid to minority interest — (15,000 ) (4,600 ) Net Cash Provided By (Used In) Financing Activities 100,064 (20,599 ) (88,516 ) Net Increase (Decrease) in Cash and Cash Equivalents (14,940 ) 78,419 (54,060 ) Cash and Cash Equivalents at Beginning of Year 163,019 84,600 138,660 Cash and Cash Equivalents at End of Year $ 148,079 $ 163,019 $ 84,600 Supplemental Disclosures of Cash Flow Information: Cash paid during the year for interest expense $ 23,171 $ 795 $ 12,541 Cash paid during the year for income taxes $ 62,505 $ 20,991 $ 11,705
at cost. S-6 For the three years ended December 31, 2003, we recorded an allowance for doubtful accounts related to interest accrued on the remaining amount owed to us by our former chief executive officer, A. E. Benton.December 31, 2003,2006, we reversedissued 0.1 million shares of restricted stock valued at $1.0 million.portion2002 restricted stock grant on a cashless basis. This resulted in 5,497 shares being held as treasury stock at cost.such allowance as a resultrestricted stock valued at $1.2 million and we wrote-off $0.9 million of unamortized debt financing costs in connection with the redemption and discharge of the 9.375 percent senior unsecured notes due November 1, 2007 (“2007 Notes”). Also during the year ended 2004, the holders of our collectionwarrants elected to exercise 45,000 warrants on a cashless basis by delivering Company shares to us. This resulted in the issuance of certain amounts owed to the Company including the portions of the note secured by our34,054 shares which are held as treasury stock and other properties (seeNote 13 – Related Party Transactions).
40 percent ownership interest in Petrodelta. Since we indirectly own 80 percent of HNR Finance B.V., we will indirectly own a net 32 percent in Petrodelta and Vinccler will indirectly own the remaining eight percent. CVP will own the remaining 60 percent. We have requested CVP to add HNR Finance as a party to the Conversion Contract. Petrodelta will be governed by its own Charter and By-Laws. S-7-— Organization and Summary of Significant Accounting Policies(Benton -Vinccler C.A. or “Benton-Vinccler”through our subsidiary Harvest Vinccler S.C.A. (“Harvest Vinccler”) in which we indirectly own an 80-percent interest. Effective April 1, 2006, our activities under our Operating Service Agreement (“OSA”) are reflected under the equity method of accounting. Since such activities are subject to the completion of the conversion of the OSA to Empresa Mixta Petrodelta S. A. (“Petrodelta”), we have not recorded any net earnings from such activities for the nine months ended December 31, 2006.until September 25, 2003, through our minority equity investmentPDVSA Petroleo S.A. (“PPSA”), to convert the OSA into Petrodelta. Upon receipt of the Venezuelan government approvals contemplated by the MOU, Harvest Vinccler and, we believe, HNR Finance B.V. and CVP will enter into a Contract of Conversion (the “Conversion Contract”). Upon execution of the Conversion Contract, Petrodelta will be formed. Subject to the conditions of the Conversion Contract, the OSA will be cancelled, Harvest Vinccler will transfer substantially all of its tangible assets and contracts, permits and rights related to the Uracoa, Tucupita and Bombal fields (“SMU fields”) in LLC Geoilbent,Venezuela to Petrodelta and Petrodelta will engage in the exploration, production, gathering, transportation and storage of hydrocarbons from the SMU fields, as well as the Isleño, Temblador and El Salto fields which will have been awarded to Petrodelta. Upon completion of conversion, HNR Finance B.V. will have a Russian entity.The equity method of accounting is used for companies and other investments in which we have significant influence. All intercompany profits, transactions and balances have been eliminated. We accounted for our investment in LLC Geoilbent (“Geoilbent”) and Arctic Gas Company (“Arctic Gas”), prior to the sale of our interests, based on a fiscal year ending September 30 (seeNote 2 – Investments In and Advances to Affiliated Companies).dollarDollar is our functional and reporting currency.EachUntil March 31, 2006, each quarter, Benton-Vinccler invoicesHarvest Vinccler invoiced PDVSA Petroleo S.A., an affiliate of Petroleos de Venezuela S.A. (“PDVSA”) or affiliates, based on barrels of oil accepted by PDVSA during the quarter, using quarterly adjusted U.S. dollarDollar contract service fees per barrel. The operating service agreement providesrelated OSA with PDVSA provided for Benton-VincclerHarvest Vinccler to receive an operating fee for each barrel of crude oil delivered and the right to receive a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannotcould not exceed the maximum total fee per barrel set forth in the agreement. In August 2005, Harvest Vinccler and PDVSA executed a Transitory Agreement (the “Transitory Agreement”) which provided that the maximum total fee per barrel paid under the OSA could not exceed 66.67 percent of the total value of the crude oil as determined under an Annex to the Transitory Agreement. This limitation was applied retroactively to January 1, 2005 and approximated 47 percent of West Texas Intermediate (“WTI”). The operating fee iswas subject to quarterly adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index. The maximum total fee is subject to quarterly adjustments to reflect changes in the average of certain world crude oil prices. EachUntil March 31, 2006, each quarter Benton-VincclerHarvest Vinccler also invoicesinvoiced PDVSA for natural gas sales based on a fixed price of $1.03 per Mcf. In addition, Benton-VincclerHarvest Vinccler agreed to sell to PDVSA 4.5 million barrels of oil
The invoices were prepared and submitted to PDVSA by the end of the first month following the end of each calendar quarter, and payment was due from PDVSA by the end of the second month following the end of each calendar quarter. Harvest Vinccler invoiced PDVSA for the first quarter 2006 delivery of its crude oil and natural gas in accordance with the Transitory Agreement. However, Harvest Vinccler recorded deferred revenue of $9.0 million for 2005 deliveries pending clarification on the calculation of crude prices under the Transitory Agreement.
At December 31, 2006, Harvest Vinccler had 58.7 billion Venezuela Bolivars (“Bolivars”) which are shown in the December 31, 2006 financial statements as $27.3 million in cash and cash equivalents.
Marketable Securities
Marketable securities are carried at cost. The marketable securities we may purchase are limited to those defined as Cash Equivalents in the indentures for our senior unsecured note. Cash Equivalents may be comprised of high-grade debt instruments, demand or time deposits, certificates of deposit and commercial paper of highly rated U.S. corporations, all having maturities of no more than 180 days. Our marketable securities at cost, which approximates fair value, consisted of $27.4 million in commercial paper at December 31, 2002.
S-7
SeeNote 2 – Long-Term Debt.
Credit Risk and Operations
natural gas deliveries since April 1, 2006.
S-8
Benton-Vincclerplace for our 2004 or 2006 production. In August 2004, Harvest Vinccler hedged a portion of its 2003 oil sales for calendar year 2005 by purchasing a WTI crude oil “put” to protect its 2003 cash flow. The put was for 10,000 barrels of oil per day for the period of March 1, 2003 through December 31, 2003. This put qualified under the highly effective test. Due to the pricing structure for our Venezuela oil, the put had the economic effect of hedging approximately 20,8005,000 barrels of oil per day. The put cost is $2.50was $4.24 per barrel, or $7.7 million, and had a strike price of $30.00$40.00 per barrel. Settlements of $1.7 million as well as the amortization of the put option cost of $7.7 million have been reflected as a net reduction to oil revenue.
Benton-VincclerIn September 2004, Harvest Vinccler hedged aan additional portion of its 2002calendar year 2005 oil sales by purchasing a commodity contract (costless collar), which required payment to (or receipts from) counterparties based on asecond WTI floor price of $23.00 and a ceiling price of $30.15crude oil put for 6,0005,000 barrels of oil per day. The collarput cost was $3.95 per barrel, or $7.2 million, and had a strike price of $44.40 per barrel. Due to the amended pricing structure as revised by the Transitory Agreement for our Venezuelan oil, these two puts had the economic effect of hedging approximately 21,500 barrels of oil per day for an average of $17.72 per barrel. These puts qualified under the highly effective test.test and the mark-to-market loss at December 31, 2004 was included in other comprehensive loss.
The notional amount of each financial instrument is basedAccumulated Other Comprehensive Loss at December 31, 2004 were reclassified to earnings during 2005. All hedging instruments expired under their own terms on expected sales of crude oil production from existing and future development wells and the related incremental oil production associated with production from high gas-to-oil ratio wells after the installation of a gas pipeline. These instruments protect our projected investment return and cash flow derived from our production by reducing the impact of a downward crude oil price movement until their expiration.
S-8
Asset Retirement Liability
Effective January 1, 2003, we adopted
Asset retirement obligations as of January 1, 2003 | $ | — | ||
Liabilities recorded during the first quarter | 4,237 | |||
Liabilities settled during the year | (733 | ) | ||
Revisions in estimated cash flows | (2,125 | ) | ||
Accretion expense | 80 | |||
Asset retirement obligations as of December 31, 2003 | $ | 1,459 | ||
December 31, | December 31, | |||||||
2006 | 2005 | |||||||
Asset retirement obligations beginning of period | $ | 2,129 | $ | 1,941 | ||||
Liabilities recorded during the period | — | 96 | ||||||
Liabilities settled during the period | — | — | ||||||
Revisions in estimated cash flows | (7 | ) | (17 | ) | ||||
Accretion expense | 31 | 109 | ||||||
Reclassified to provisional equity affiliate | (2,153 | ) | — | |||||
Asset retirement obligations end of period | $ | — | $ | 2,129 | ||||
$2.8 million.
S-9
S-9
Statement of Financial Accounting Standards No. 141 – Business Combinations (“FAS 141”) and No. 142 – Goodwill and Other Intangible Assets (“FAS 142”) included new terminology on the disclosure of what constitutes an intangible asset. One interpretation being considered relative to these standards is that a mineral interest associated with proved and undeveloped oil and gas leasehold acquisition costs should be classified separately in Oil and Gas Properties on the Consolidated Balance Sheet as intangible assets, and the disclosures required by FAS 141 and FAS 142 would be included in the Notes to Financial Statements. We believe that the presentation and disclosure of the $2.9 million excluded costs attributed to the China cost center is appropriate pending further guidance on this matter.
All capitalized costs (including oilfield inventory and future abandonment costs under SFAS 143) and estimated future development costs (including estimated dismantlement, restoration and abandonment costs) of proved reserves are depleted using the units of production method based on the total proved reserves of the country cost center. Depletion expense, which was substantially all attributable to the Venezuelan cost center for the years ended December 31, 2003, 20022006, 2005 and 20012004 was $19.6$9.9 million, $24.9$41.2 million and $22.1$34.1 million ($2.52,3.74, $3.16 and $2.56 and $2.26 per equivalent barrel), respectively.
2003 | 2002 | 2006 | 2005 | |||||||||||||
Proved property costs | $ | 582,456 | $ | 566,415 | $ | — | 630,634 | |||||||||
Costs excluded from amortization | 2,900 | 2,900 | 2,900 | 2,900 | ||||||||||||
Material and supply inventories | 8,266 | 7,286 | ||||||||||||||
Oilfield inventories | — | 8,150 | ||||||||||||||
Other administrative property | 8,948 | 7,503 | 1,375 | 9,568 | ||||||||||||
602,570 | 584,104 | 4,275 | 651,252 | |||||||||||||
Accumulated depletion, impairment and depreciation | (418,507 | ) | (439,344 | ) | (955 | ) | (491,924 | ) | ||||||||
$ | 184,063 | $ | 144,760 | $ | 3,320 | $ | 159,328 | |||||||||
provisional equity affiliate.
S-10
S-10
2005 | 2004 | |||||||
(in thousands, except per share data) | ||||||||
Net income, as reported | $ | 50,839 | $ | 34,360 | ||||
Add: Stock-based employee compensation cost, net of tax | 2,635 | 999 | ||||||
Less: Total stock-based employee compensation cost determined under fair value based method, net of tax | (2,711 | ) | (1,382 | ) | ||||
Net income – proforma | $ | 50,763 | $ | 33,977 | ||||
Net income per common share: | ||||||||
Basic – as reported | $ | 1.38 | $ | 0.95 | ||||
Basic – proforma | $ | 1.37 | $ | 0.94 | ||||
Diluted – as reported | $ | 1.32 | $ | 0.90 | ||||
Diluted – proforma | $ | 1.32 | $ | 0.89 | ||||
2003 | 2002 | 2001 | ||||||||||
Net income, as reported | $ | 27,303 | $ | 100,362 | $ | 43,237 | ||||||
Add: Stock-based employee compensation cost, net of tax | 296 | 915 | 35 | |||||||||
Less: Total stock-based employee compensation cost determined under fair value based method, net of tax | (1,056 | ) | (2,905 | ) | (2,459 | ) | ||||||
Net income – proforma | $ | 26,543 | $ | 98,372 | $ | 40,813 | ||||||
Net income per common share: | ||||||||||||
Basic – as reported | $ | 0.77 | $ | 2.90 | $ | 1.27 | ||||||
Basic – proforma | $ | 0.75 | $ | 2.87 | $ | 1.20 | ||||||
Diluted – as reported | $ | 0.74 | $ | 2.78 | $ | 1.27 | ||||||
Diluted – proforma | $ | 0.72 | $ | 2.75 | $ | 1.20 | ||||||
S-11
The book values of all financial instruments, other than long-term debt, are representative of their fair values due to their short-term maturities. The aggregate fair value of our senior unsecured notes, based on the last trading prices at December 31, 2003 and 2002, was approximately $85.0 million and $77.4 million, respectively.
S-11
market gains/(losses)mark-to-market losses from cash flow hedging activities as other comprehensive income/(loss)loss during the yearsyear ended December 31, 20032004 and 2002.
in accordance with SFAS 130, have provided a separate line in the audited consolidated statement of operations and comprehensive income.
position, results of operations or cash flows.
S-12
effect on our consolidated financial position, results of operations and cash flows.
On September 25, 2003, we sold our minority equity investment in Geoilbent to Yukos Operational Holding Limited and recognized a pre-tax gain on the sale of $46.6 million (seeNote 9 – Russian Operations). Prior to the sale, our 34 percent minority equity investment in Geoilbent was accounted for using the equity method due to the significant influence we exercised over their operations and management. Investments included amounts paid to the investee company for shares of stock and other costs incurred associated with the acquisition and evaluation of technical data for the oil fields operated by the investee company. Equity in earnings of Geoilbent is based on a fiscal year ending September 30. No dividends have been paid to us from Geoilbent.
Equity in earnings and losses and investments in and advances to Geoilbent are as follows (in thousands):
S-12
LLC Geoilbent | ||||||||
2003 | 2002 | |||||||
Investments: | ||||||||
In equity in net assets | $ | — | $ | 28,056 | ||||
Other costs, net of amortization | — | (263 | ) | |||||
Total investments | — | 28,319 | ||||||
Advances | — | 2,527 | ||||||
Equity in earnings | — | 20,937 | ||||||
Total | $ | — | $ | 51,783 | ||||
Note 3 — Long-Term Debt and Liquidity
December 31, | December 31, | |||||||
2003 | 2002 | |||||||
Senior unsecured notes with interest at 9.375% | ||||||||
See description below | $ | 85,000 | $ | 85,000 | ||||
Note payable with interest at 6.1% | ||||||||
See description below | 2,700 | 3,900 | ||||||
Note payable with interest at 39.7% | ||||||||
See description below | — | 2,167 | ||||||
Note payable with interest at 7.1% | 15,500 | 15,500 | ||||||
103,200 | 106,567 | |||||||
Less current portion | 6,367 | 1,867 | ||||||
$ | 96,833 | $ | 104,700 | |||||
December 31, | December 31, | |||||||
2006 | 2005 | |||||||
Note payable with interest at 10.0% | $ | 55,814 | $ | — | ||||
Note payable with interest at 10.0% | 39,535 | — | ||||||
Note payable with interest at 10.0% | 9,302 | — | ||||||
Note payable with interest at 9.0% | — | 300 | ||||||
Note payable with interest at 11.5% | — | 5,167 | ||||||
104,651 | 5,467 | |||||||
Less current portion | 37,674 | 5,467 | ||||||
$ | 66,977 | $ | — | |||||
In
In March 2001, Benton-Vinccler borrowed $12.3 million from a Venezuelan commercial bank, for construction of an oil pipeline. The loan is in two parts, with the first part in an original principal amount of $6.0 million that bears interest payable monthly based on 90-day London Interbank Borrowing Rate (“LIBOR”) plus 5 percent with principal payable quarterly for five years. The second part,21 billion Bolivars (approximately $9.8 million), and 21 billion Bolivars (approximately $9.8 million) every 180 days thereafter. A payment in the original principal amount of 4.420 billion Venezuelan Bolivars (“Bolivars”) (approximately $6.3$9.3 million). The Bolivar loan was repaid as of March 31, 2003. The loans provide for certain limitationsmade on mergers and sale of assets. We have guaranteed the repayment of this loan.
In October 2002, Benton-Vinccler, C.A. executed a note and borrowed $15.5 million to fund construction of a gas pipeline and related facilities to deliver natural gas from the Uracoa field to a PDVSA pipeline.December 18, 2006. The interest rate for thisthe first year is fixed at 10.0 percent and will be negotiated for the second year subject to a maximum of 95 percent of the average interest rate charged by six major Venezuelan banks. This loan is 90-day LIBOR plus 6 percentage points.collateralized by a $40.0 million deposit in a U.S. bank. The term is four years with a quarterly amortization of $1.3 million beginning with the first quarter 2004 to coincide with the first payment from our gas sales.
Benton-Vinccler’s oil and gas pipeline project loans allow the lender to accelerate repayment if production ceases for a period greater than thirty days. During the production shut-in which started in December 2002, Benton-Vincclerloan was granted a waiver of this provision until February 18, 2003 in exchange for a prepayment of the next two principal obligations aggregating $0.9 million. This prepayment, while using cash reserves, reduced our net interest expense as the current interest expense was more than the current interest income earned on the invested funds. On February 8, 2003, Benton-Vinccler commenced production, thereby eliminating the need for an additional waiver. A future disruption of production could trigger the debt acceleration provision again. While no assurances can be given, we believe Benton-Vinccler would be able to obtain another waiver.
The terms of the 2007 Notes require that net cash proceeds in excess of $25 million from the sale of Geoilbent must be invested in the oil and gas business within one year of the sale, or any amount not so invested must be used to repay or prepaymeet the 2007 Notes or certain debts of subsidiaries.
S-13
2004 | $ | 6,367 | ||
2005 | 6,367 | |||
2006 | 5,466 | |||
2007 | 85,000 | |||
$ | 103,200 | |||
Liquidity
We currently have10.0 percent and may be adjusted from time to time thereafter within the limits set forth by the Central Bank of Venezuela or in accordance with the conditions in the financial market. The loan is collateralized by a significant debt obligation payable$40.4 million deposit in November 2007 of $85 million. Our abilitya U.S. bank. The loan will be used to meet our debt obligationsthe SENIAT income tax assessments and related interest, refinance a portion of the Bolivar loan and to reduce our level of debt depends on the successful implementation of our strategic objectives. Our cash flow from operations complemented with our cash and cash equivalents of $139 million at December 31, 2003, can be invested in other opportunities used to develop our significant proved undeveloped reserves or used to repurchase our outstanding debt.
fund operating requirements.
2008.
$13,200 and $4,000 per month, respectively.
S-14
adverse impact on our financial condition, results of operations and cash flows.
Benton-Vinccler pays a
2003 | 2002 | 2001 | 2006 | 2005 | 2004 | |||||||||||||||||||
Venezuelan municipal taxes | $ | 2,741 | $ | 3,805 | $ | 4,447 | $ | 3,191 | $ | 5,788 | $ | 4,485 | ||||||||||||
Franchise taxes | 341 | 139 | 121 | 175 | (70 | ) | 464 | |||||||||||||||||
Payroll and other taxes | 291 | 124 | 802 | 582 | 640 | 612 | ||||||||||||||||||
$ | 3,373 | $ | 4,068 | $ | 5,370 | $ | 3,948 | $ | 6,358 | $ | 5,561 | |||||||||||||
S-14
In 2005, Venezuela modified the Science and Technology Law to require companies doing business in Venezuela to invest, contribute, or spend a percentage of their gross revenue on projects to promote inventions or investigate technology in areas deemed critical to Venezuela.
2003 | 2002 | |||||||
Deferred tax assets: | ||||||||
Operating loss carryforwards | $ | 20,442 | $ | 19,690 | ||||
Difference in basis of property | 29,602 | 21,495 | ||||||
Other | 3,070 | 2,043 | ||||||
Valuation allowance | (48,365 | ) | (39,146 | ) | ||||
Net deferred tax asset | $ | 4,749 | $ | 4,082 | ||||
S-15
2006 | 2005 | |||||||
Deferred tax assets: | ||||||||
Operating loss carryforwards | $ | 7,466 | $ | 2,020 | ||||
Difference in basis of assets | 25,343 | 25,343 | ||||||
Deferred revenue | 5,608 | 3,052 | ||||||
Valuation allowance | (32,809 | ) | (27,363 | ) | ||||
Net deferred tax asset | 5,608 | 3,052 | ||||||
Less current portion | 5,608 | 3,052 | ||||||
$ | — | $ | — | |||||
The difference in interpretation of oil pricing under the OSA has been recognized and represents our entire deferred tax asset.
2003 | 2002 | 2001 | 2006 | 2005 | 2004 | |||||||||||||||||||
Income (loss) before income taxes | ||||||||||||||||||||||||
United States | $ | 21,812 | $ | 89,455 | $ | (26,572 | ) | $ | (15,688 | ) | $ | 8,178 | $ | (16,593 | ) | |||||||||
Foreign | 49,976 | 80,356 | 33,754 | 7,316 | 114,916 | 97,859 | ||||||||||||||||||
Total | $ | 71,788 | $ | 169,811 | $ | 7,182 | $ | (8,372 | ) | $ | 123,094 | $ | 81,266 | |||||||||||
2003 | 2002 | 2001 | 2006 | 2005 | 2004 | |||||||||||||||||||
Current: | ||||||||||||||||||||||||
United States | $ | 1,188 | $ | 353 | $ | 1 | $ | — | $ | 739 | $ | (8 | ) | |||||||||||
Foreign | 9,136 | 6,324 | 6,700 | 63,473 | 53,304 | 34,581 | ||||||||||||||||||
$ | 10,324 | $ | 6,677 | $ | 6,701 | 63,473 | 54,043 | 34,573 | ||||||||||||||||
Deferred: | ||||||||||||||||||||||||
United States | $ | — | $ | 53,413 | (42,405 | ) | ||||||||||||||||||
Foreign | (667 | ) | 205 | 6 | (2,556 | ) | 2,982 | (1,285 | ) | |||||||||||||||
(667 | ) | 53,618 | (42,399 | ) | $ | 60,917 | $ | 57,025 | $ | 33,288 | ||||||||||||||
$ | 9,657 | $ | 60,295 | $ | (35,698 | ) | ||||||||||||||||||
During 2003, we reduced our foreign tax provision approximately $3.9 million related to the resolution of certain prior year foreign income tax matters. Additionally, we recorded a domestic tax provision of approximately $1.1 million related to certain domestic tax matters identified during the year.
2003 | 2002 | 2001 | ||||||||||
Computed tax expense at the statutory rate | $ | 15,025 | $ | 59,348 | 4,580 | |||||||
State income taxes | 1,188 | 353 | — | |||||||||
Effect of foreign source income and rate differentials on foreign income | (15,849 | ) | (19,373 | ) | 1,675 | |||||||
Change in valuation allowance | 9,219 | 19,446 | (53,413 | ) | ||||||||
Prior year adjustments | — | — | 2,304 | |||||||||
Reclass paid-in capital | — | — | 11,007 | |||||||||
All other | 74 | 80 | 215 | |||||||||
Sub-total income tax expense (benefit) | 9,657 | 59,854 | (33,632 | ) | ||||||||
Effects of recording equity income of certain affiliated Companies on an after-tax basis | — | 441 | (2,066 | ) | ||||||||
Total income tax expense (benefit) | $ | 9,657 | $ | 60,295 | $ | (35,698 | ) | |||||
2006 | 2005 | 2004 | ||||||||||
Computed tax expense at the statutory rate | $ | (2,930 | ) | $ | 43,083 | $ | 28,443 | |||||
State income taxes | — | — | 25 | |||||||||
Effect of foreign source income and rate differentials on foreign income | 8,563 | 16,065 | (2,169 | ) | ||||||||
Change in valuation allowance | 5,446 | 13,129 | 7,020 | |||||||||
Alternative minimum tax | — | 739 | — | |||||||||
Venezuela tax settlement | 49,793 | — | — | |||||||||
Net operating loss utilization | — | (15,567 | ) | — | ||||||||
Other | 45 | (424 | ) | (31 | ) | |||||||
Total income tax expense | $ | 60,917 | $ | 57,025 | $ | 33,288 | ||||||
S-15
At December 31, 2003,2006, we had, for federal income tax purposes, operating loss carryforwards of approximately $58.4$21.3 million, expiring in the years 20182021 through 2022.2026.
S-16
The amount of deferred taxes on the undistributed earnings cannot be determined at this time.
S-17
2003 | 2002 | 2001 | 2006 | 2005 | 2004 | |||||||||||||||||||||||||||||||||||||||||||
Weighted | Weighted | Weighted | Weighted | Weighted | Weighted | |||||||||||||||||||||||||||||||||||||||||||
Average | Average | Average | Average | Average | Average | |||||||||||||||||||||||||||||||||||||||||||
Exercise | Exercise | Exercise | Exercise | Exercise | Exercise | |||||||||||||||||||||||||||||||||||||||||||
Price | Shares | Price | Shares | Price | Shares | Price | Shares | Price | Shares | Price | Shares | |||||||||||||||||||||||||||||||||||||
Outstanding at beginning of the year: | $ | 7.42 | 5,223 | $ | 6.36 | 6,865 | 7.74 | 5,660 | $ | 8.61 | 4,070 | $ | 8.18 | 3,793 | $ | 7.52 | 4,523 | |||||||||||||||||||||||||||||||
Options granted | 6.26 | 246 | 4.84 | 165 | 1.65 | 1,684 | 10.62 | 558 | 11.51 | 922 | 13.36 | 378 | ||||||||||||||||||||||||||||||||||||
Options exercised | 2.32 | (494 | ) | 2.21 | (1,515 | ) | — | — | (5.69 | ) | (65 | ) | (3.45 | ) | (241 | ) | (7.41 | ) | (955 | ) | ||||||||||||||||||||||||||||
Options cancelled | 11.37 | (452 | ) | 8.03 | (292 | ) | 6.43 | (479 | ) | (19.96 | ) | (440 | ) | (14.24 | ) | (404 | ) | (6.31 | ) | (153 | ) | |||||||||||||||||||||||||||
Outstanding at end of the year | 7.52 | 4,523 | 7.42 | 5,223 | 6.36 | 6,865 | 7.70 | 4,123 | 8.61 | 4,070 | 8.18 | 3,793 | ||||||||||||||||||||||||||||||||||||
Exercisable at end of the year | 8.18 | 3,857 | 8.49 | 4,360 | 8.32 | 4,800 | 5.91 | 2,719 | 7.40 | 2,886 | 7.71 | 3,236 | ||||||||||||||||||||||||||||||||||||
Outstanding | Exercisable | |||||||||||||||||||||||||||
Range of | Number | Weighted-Average | Number | |||||||||||||||||||||||||
Exercise | Outstanding At | Remaining | Weighted-Average | Exercisable at | Weighted-Average | |||||||||||||||||||||||
Prices | December 31, 2003 | Contractual Life | Exercise Price | December 31, 2003 | Exercise Price | |||||||||||||||||||||||
$ | 1.55 | - | $ | 2.75 | 2,027,150 | 5.91 | $ | 1.97 | 1,679,983 | $ | 2.03 | |||||||||||||||||
$ | 4.80 | - | $ | 7.00 | 621,000 | 4.69 | 5.81 | 337,667 | 5.87 | |||||||||||||||||||
$ | 7.25 | - | $ | 11.00 | 488,633 | 1.69 | 8.77 | 452,633 | 8.90 | |||||||||||||||||||
$ | 11.50 | - | $ | 16.50 | 946,665 | 1.42 | 13.52 | 946,665 | 13.52 | |||||||||||||||||||
$ | 17.38 | - | $ | 24.13 | 439,833 | 1.78 | 21.21 | 439,833 | 21.21 | |||||||||||||||||||
4,523,281 | 3,856,781 | |||||||||||||||||||||||||||
Outstanding | Exercisable | |||||||||||||||||||||||||||
Weighted- | ||||||||||||||||||||||||||||
Average | Weighted- | Weighted- | ||||||||||||||||||||||||||
Range of | Number | Remaining | Average | Aggregate | Number | Average | Aggregate | |||||||||||||||||||||
Exercise | Outstanding | Contractual | Exercise | Intrinsic | Exercisable | Exercise | Intrinsic | |||||||||||||||||||||
Prices | at 12/31/06 | Life | Price | Value | at 12/31/06 | Price | Value | |||||||||||||||||||||
$ 1.55 - $ 2.75 | 1,486 | 3.84 | $ | 1.97 | $ | 12,866 | 1,486 | $ | 1.97 | $ | 12,866 | |||||||||||||||||
$ 4.80 - $ 7.10 | 350 | 5.61 | 5.65 | 1,744 | 350 | 5.65 | 1,744 | |||||||||||||||||||||
$ 8.72 - $10.91 | 1,121 | 7.26 | 10.08 | 716 | 159 | 8.90 | 275 | |||||||||||||||||||||
$11.88 - $16.90 | 1,103 | 5.40 | 13.00 | — | 661 | 12.92 | — | |||||||||||||||||||||
$18.25 - $19.75 | 63 | 0.45 | 19.04 | — | 63 | 19.04 | — | |||||||||||||||||||||
4,123 | $ | 15,326 | 2,719 | $ | 14,885 | |||||||||||||||||||||||
S-16S-18
Of
2006 | 2005 | 2004 | ||||||||||
For options granted during: | ||||||||||||
Weighted average fair value | $ | 5.98 | $ | 6.35 | $ | 10.33 | ||||||
Weighted averaged expected life | 7 | 7 | 2-10 | |||||||||
Valuation assumptions: | ||||||||||||
Expected volatility | 49.9%-53.3 | % | 50.0%-53.4 | % | 69.6 | % | ||||||
Risk-free interest rate | 4.6%-5.2 | % | 3.9%-4.6 | % | 2.6%-4.8 | % | ||||||
Expected dividend yield | 0 | % | 0 | % | 0 | % | ||||||
Expected annual forfeitures | 3 | % | 3 | % | 0 | % |
In connection with our acquisitionperiods within the contractual life of Benton Offshore China Companythe option is based on the U.S. Treasury yield curve in December 1996, we adoptedeffect at the Benton Offshore China Company 1996 Stock Option Plan.time of grant. Under the plan, Benton Offshore China Company is authorized to issue up to 107,571Black-Scholes option pricing model, the weighted-average estimated values of stock options to purchase our common stock for $7.00 per share. The plan was adopted in substitution of Benton Offshore China Company’s stock option plan,granted during 2006, 2005 and all options to purchase shares of Benton Offshore China Company common stock2004 were replaced under the plan by options to purchase shares$5.98, $6.35 and $10.33, respectively.
Weighted-Average | ||||||||
Grant-Date | ||||||||
Nonvested Shares | Shares | Fair Value | ||||||
Nonvested at January 1, 2006 | 1,185 | $ | 7.30 | |||||
Granted | 557 | 5.98 | ||||||
Vested | (328 | ) | 7.81 | |||||
Forfeited | (10 | ) | 11.73 | |||||
Nonvested at December 31, 2006 | 1,404 | $ | 6.75 | |||||
2004 was $4.1 million, $2.7 million and $1.4 million, respectively.
The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at December 31, 2003 were (warrants in thousands):
Warrants | ||||||||||||||
Date Issued | Expiration Date | Exercise Price | Issued | Outstanding | ||||||||||
July 1994 | July 2004 | $ | 7.50 | 150 | 8 | |||||||||
December 1994 | December 2004 | 12.00 | 50 | 50 | ||||||||||
June 1995 | June 2007 | 17.09 | 125 | 125 | ||||||||||
325 | 183 | |||||||||||||
Note 86 — Operating Segments
S-17
Year ended December 31, 2003:
(in thousands) | Venezuela | USA and Other | Russia | Eliminations | Consolidated | |||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | $ | 103,920 | $ | — | $ | — | $ | — | $ | 103,920 | ||||||||||
Gas sales | 2,740 | — | — | — | 2,740 | |||||||||||||||
Ineffective hedge activity | (565 | ) | — | — | — | (565 | ) | |||||||||||||
106,095 | — | — | — | 106,095 | ||||||||||||||||
Expenses | ||||||||||||||||||||
Operating expenses | 31,309 | 76 | (492 | ) | — | 30,893 | ||||||||||||||
Depletion, depreciation and amortization | 21,035 | 109 | 44 | — | 21,188 | |||||||||||||||
General and administrative | 4,031 | 10,514 | 1,201 | — | 15,746 | |||||||||||||||
Arbitration settlement | — | 1,477 | — | — | 1,477 | |||||||||||||||
Bad debt recovery | — | (374 | ) | — | — | (374 | ) | |||||||||||||
Taxes other than on income | 2,921 | 447 | 5 | — | 3,373 | |||||||||||||||
Total expenses | 59,296 | 12,249 | 758 | — | 72,303 | |||||||||||||||
Income (loss) from operations | 46,799 | (12,249 | ) | (758 | ) | — | 33,792 | |||||||||||||
Other non-operating income (expense) | ||||||||||||||||||||
Gain on disposition of assets | — | 46,619 | — | — | 46,619 | |||||||||||||||
Investment earnings and other | 435 | 983 | — | — | 1,418 | |||||||||||||||
Interest expense | (1,944 | ) | (8,470 | ) | — | 9 | (10,405 | ) | ||||||||||||
Net gain on exchange rates | 495 | 34 | — | — | 529 | |||||||||||||||
Intersegment revenues (expenses) | (7,484 | ) | 7,484 | — | — | — | ||||||||||||||
Equity in losses of affiliated companies | — | — | (28,860 | ) | — | (28,860 | ) | |||||||||||||
(8,498 | ) | 46,650 | (28,860 | ) | 9 | 9,301 | ||||||||||||||
Income (loss) before income taxes | 38,301 | 34,401 | (29,618 | ) | 9 | 43,093 | ||||||||||||||
Income tax expense | 8,459 | 1,187 | 2 | 9 | 9,657 | |||||||||||||||
Operating segment income (loss) | 29,842 | 33,214 | (29,620 | ) | — | 33,436 | ||||||||||||||
Write-downs of oil and gas properties and impairments | — | (165 | ) | — | — | (165 | ) | |||||||||||||
Minority interest | (5,968 | ) | — | — | — | (5,968 | ) | |||||||||||||
Net income (loss) | $ | 23,874 | $ | 33,049 | $ | (29,620 | ) | $ | — | $ | 27,303 | |||||||||
Total assets | $ | 241,855 | $ | 180,768 | $ | 237 | $ | (48,512 | ) | $ | 374,348 | |||||||||
Additions to properties | $ | 60,589 | $ | 245 | $ | 91 | $ | — | $ | 60,925 | ||||||||||
Year ended December 31, 2002
(in thousands) | Venezuela | USA and Other | Russia | Eliminations | Consolidated | |||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | $ | 127,015 | $ | — | $ | — | $ | — | $ | 127,015 | ||||||||||
Ineffective hedge activity | (284 | ) | — | — | — | (284 | ) | |||||||||||||
126,731 | — | — | — | 126,731 | ||||||||||||||||
Expenses | ||||||||||||||||||||
Operating expenses | 31,457 | 360 | 2,133 | — | 33,950 | |||||||||||||||
Depletion, depreciation and amortization | 23,850 | 2,483 | 30 | — | 26,363 | |||||||||||||||
General and administrative | 4,310 | 11,420 | 774 | — | 16,504 | |||||||||||||||
Bad debt recovery | — | (3,276 | ) | — | (3,276 | ) | ||||||||||||||
Taxes other than on income | 3,997 | 71 | — | — | 4,068 | |||||||||||||||
Total expenses | 63,614 | 11,058 | 2,937 | — | 77,609 | |||||||||||||||
Income (loss) from operations | 63,117 | (11,058 | ) | (2,937 | ) | — | 49,122 | |||||||||||||
Other non-operating income (expense): | ||||||||||||||||||||
Gain on disposition of assets | — | 144,032 | (3 | ) | — | 144,029 | ||||||||||||||
Gain on early extinguishment of debt | — | 874 | — | — | 874 | |||||||||||||||
Investment earnings and other | 1,889 | 1,653 | — | (1,462 | ) | 2,080 | ||||||||||||||
Interest expense | (4,237 | ) | (13,611 | ) | — | 1,538 | (16,310 | ) | ||||||||||||
Net gain on exchange rates | 4,356 | 197 | — | — | 4,553 | |||||||||||||||
Intersegment revenues (expenses) | 15,156 | (15,156 | ) | — | — | — | ||||||||||||||
Equity in income of affiliated companies | — | — | 165 | — | 165 | |||||||||||||||
17,164 | 117,989 | 162 | 76 | 135,391 | ||||||||||||||||
Income (loss) before income taxes | 80,281 | 106,931 | (2,775 | ) | 76 | 184,513 | ||||||||||||||
Income tax expense | 6,453 | 53,764 | 2 | 76 | 60,295 | |||||||||||||||
Operating segment income (loss) | 73,828 | 53,167 | (2,777 | ) | — | 124,218 | ||||||||||||||
Write-downs of oil and gas properties and impairments | — | (14,537 | ) | — | — | (14,537 | ) | |||||||||||||
Minority interest | (9,319 | ) | — | — | — | (9,319 | ) | |||||||||||||
Net income (loss) | $ | 64,509 | $ | 38,630 | $ | (2,777 | ) | $ | — | $ | 100,362 | |||||||||
Total assets | $ | 209,733 | $ | 122,355 | $ | 52,302 | $ | (49,198 | ) | $ | 335,192 | |||||||||
Additions to properties | $ | 42,486 | 738 | 122 | — | 43,346 | ||||||||||||||
S-18
Year ended December 31, 2001:
(in thousands) | Venezuela | USA and Other | Russia | Eliminations | Consolidated | |||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | $ | 122,386 | $ | — | $ | — | $ | — | $ | 122,386 | ||||||||||
Expenses | ||||||||||||||||||||
Operating expenses | 42,037 | 55 | 667 | — | 42,759 | |||||||||||||||
Depletion, depreciation and amortization | 22,096 | 3,408 | 12 | — | 25,516 | |||||||||||||||
General and administrative | 4,151 | 14,972 | 949 | — | 20,072 | |||||||||||||||
Taxes other than on income | 4,666 | 704 | — | — | 5,370 | |||||||||||||||
Total expenses | 72,950 | 19,139 | 1,628 | — | 93,717 | |||||||||||||||
Income (loss) from operations | 49,436 | (19,139 | ) | (1,628 | ) | — | 28,669 | |||||||||||||
Other non-operating income (expense): | ||||||||||||||||||||
Investment earnings and other | 5,995 | 2,053 | 60 | (5,020 | ) | 3,088 | ||||||||||||||
Interest expense | (7,403 | ) | (22,695 | ) | — | 5,223 | (24,875 | ) | ||||||||||||
Net gain on exchange rates | 732 | 36 | — | — | 768 | |||||||||||||||
Intersegment revenues (expenses) | (14,983 | ) | 14,983 | — | — | — | ||||||||||||||
Equity in income of affiliated companies | — | — | 5,902 | — | 5,902 | |||||||||||||||
(15,659 | ) | (5,623 | ) | 5,962 | 203 | (15,117 | ) | |||||||||||||
Income (loss) before income taxes | 33,777 | (24,762 | ) | 4,334 | 203 | 13,552 | ||||||||||||||
Income tax (benefit) expense | 6,491 | (42,392 | ) | — | 203 | (35,698 | ) | |||||||||||||
Operating segment income | 27,286 | 17,630 | 4,334 | — | 49,250 | |||||||||||||||
Write-down of oil and gas properties and impairments | — | (468 | ) | — | — | (468 | ) | |||||||||||||
Minority interest | (5,545 | ) | — | — | — | (5,545 | ) | |||||||||||||
Net income | $ | 21,741 | $ | 17,162 | 4,334 | — | $ | 43,237 | ||||||||||||
Total assets | $ | 167,671 | $ | 165,254 | $ | 100,801 | $ | (85,575 | ) | $ | 348,151 | |||||||||
Additions to properties | $ | 43,411 | $ | — | $ | 31 | $ | — | $ | 43,442 | ||||||||||
S-19
2006 | 2005 | 2004 | ||||||||||
(in thousands) | ||||||||||||
Segment Revenues | ||||||||||||
Oil and gas sales: | ||||||||||||
Venezuela | $ | 59,506 | $ | 236,941 | $ | 186,066 | ||||||
Total oil and gas sales | 59,506 | 236,941 | 186,066 | |||||||||
Segment Income (Loss) | ||||||||||||
Venezuela | (42,895 | ) | 64,096 | 54,469 | ||||||||
United States and other | (15,667 | ) | (13,257 | ) | (20,109 | ) | ||||||
Net income (loss) | $ | (58,562 | ) | $ | 50,839 | $ | 34,360 | |||||
December 31, | December 31, | |||||||
2006 | 2005 | |||||||
(in thousands) | ||||||||
Operating Segment Assets | ||||||||
Venezuela | $ | 306,289 | $ | 258,268 | ||||
United States and other | 155,973 | 161,328 | ||||||
462,262 | 419,596 | |||||||
Intersegment eliminations | (39,551 | ) | (18,798 | ) | ||||
$ | 422,711 | $ | 400,798 | |||||
Geoilbent
2003 | 2002 | 2001 | ||||||||||
Year ended September 30: | ||||||||||||
Revenues | ||||||||||||
Oil sales | $ | 81,724 | $ | 91,598 | $ | 101,159 | ||||||
Expenses | ||||||||||||
Selling and distribution expenses | 5,893 | 6,696 | 9,876 | |||||||||
Operating expenses | 15,897 | 15,360 | 11,415 | |||||||||
Depletion, depreciation and amortization | 18,182 | 27,168 | 14,918 | |||||||||
Write-downs of oil and gas properties | 95,000 | — | — | |||||||||
General and administrative | 9,456 | 8,335 | 5,650 | |||||||||
Taxes other than on income | 25,626 | 27,657 | 26,011 | |||||||||
170,054 | 85,216 | 67,870 | ||||||||||
Income (loss) from operations | (88,330 | ) | 6,382 | 33,289 | ||||||||
Other non-operating income (expense) | ||||||||||||
Investment earnings and other | 1,064 | 381 | 648 | |||||||||
Interest expense | (1,992 | ) | (4,629 | ) | (7,547 | ) | ||||||
Net gain on exchange rates | 1,566 | 2,053 | 781 | |||||||||
638 | (2,195 | ) | (6,118 | ) | ||||||||
Income (loss) before income taxes | (87,692 | ) | 4,187 | 27,171 | ||||||||
Income tax expense | (3,117 | ) | 302 | 6,751 | ||||||||
(84,575 | ) | 3,885 | 20,420 | |||||||||
Effects of change in accounting policy | 310 | — | — | |||||||||
Net income (loss) | $ | (84,885 | ) | $ | 3,885 | $ | 20,420 | |||||
At September 30: | ||||||||||||
Current assets | $ | 18,785 | $ | 35,447 | ||||||||
Other assets | 186,815 | 187,706 | ||||||||||
Current liabilities | 54,051 | 60,439 | ||||||||||
Other liabilities | 7,500 | 22,550 | ||||||||||
Net equity | 144,049 | 140,164 |
As of September 30, 2002, the Geoilbent shareholders had provided Geoilbent with subordinate loans totaling $7.5 million ($2.5 million from us). These loans were unsecured, repayable in January 2004 and recorded as a current liability at September 30, 2003. The loan by us was repaid as part of the sale of our minority equity investment in Geoilbent. As of January 1, 2003, the Russian economy was no longer a highly inflationary economy.expenses since March 31, 2006. As a result the Russian Ruble became the functional currency and not the U.S. dollar.
S-20
Arctic Gas Company
On April 12, 2002, we soldof this situation, our 68 percent equity interestconsolidated financial statements prepared in Arctic Gas. The equity earnings of Arctic Gas have historically been based on a fiscal year ended September 30. The fourth quarter of 2001, the first quarter of 2002 and the first twelve days of April have been included in the results for 2002.
We accounted for our interest in Arctic Gas using the equity method due to the significant influence we exercised over the operating and financial policies of Arctic Gas. Our weighted-average equity interest,accordance with GAAP for the year ended December 31, 2001 was 39 percent.2006, do not reflect the net results of our producing operations in Venezuela for the last three quarters of the year. We recordedwill not be able to include the results of our Venezuelan operations in our consolidated financial statements until the conversion to Petrodelta is completed. Although the MOU provides that upon completion of the conversion, there will be an adjustment between the parties to obtain the same economic result as our shareif the conversion had been completed on April 1, 2006, this adjustment will not occur until the conversion is completed.
S-20
2002 | 2001 | |||||||
Year ended September 30: | ||||||||
Revenues | ||||||||
Oil Sales | $ | 7,880 | $ | 13,374 | ||||
Expenses | ||||||||
Selling and distribution expenses | 3,170 | 3,867 | ||||||
Operating expense | 2,473 | 3,483 | ||||||
Depletion, depreciation and amortization | 333 | 1,032 | ||||||
General and administrative | 2,112 | 3,025 | ||||||
Taxes other than on income | 1,261 | 3,881 | ||||||
9,349 | 15,288 | |||||||
Loss from operations | (1,469 | ) | (1,914 | ) | ||||
Other non-operating income (expense) | ||||||||
Other income (expense) | (4 | ) | 54 | |||||
Interest and foreign exchange expense | (1,722 | ) | (1,848 | ) | ||||
(1,726 | ) | (1,794 | ) | |||||
Loss before income taxes | (3,195 | ) | (3,708 | ) | ||||
Income tax expense | — | — | ||||||
Net loss | $ | (3,195 | ) | $ | (3,708 | ) | ||
Note 10 - Venezuela Operations
On July 31, 1992, we and our partner, Venezolana de Inversiones y Construcciones Clerico, C.A. (“Vinccler”), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., then one of three exploration and production affiliates of the national oil company, PDVSA.These loans are collateralized by $88.9 million deposited in two U.S. banks. The operating service agreement covers the Uracoa, Bombal and Tucupita Fields that comprise the South Monagas Unit. Under the terms of the operating service agreement, Benton-Vinccler, a Venezuelan corporation owned 80 percent by us and 20 percent by Vinccler, is a contractor for PDVSA and is responsible for overall operations of the South Monagas Unit, including all necessary investments to reactivate and develop the fields comprising the South Monagas Unit. Benton-Vinccler receives an operating fee in U.S. dollars deposited into a U.S. commercial bank account for each barrel of crude oil produced (subject to periodic adjustments to reflect changes in a special energy index of the U.S. Consumer Price Index) and is reimbursed according to a prescribed formula in U.S. dollars for its capital costs, provided that such operating fee and cost recovery fee cannot exceed the maximum dollar amount per barrel set forth in the agreement.
In September 2002, Benton-Vinccler and PDVSA signed an amendment to the operating service agreement, providing for the delivery of up to 198 Bcf of natural gas through July 2012 at a price of $1.03 per Mcf. Natural gas sales commenced in the fourth quarter of 2003. In addition, Benton-Vinccler agreed to sell to PDVSA 4.5 million barrels of oil stipulated as additional volumes resulting from the gas production at $7.00 per barrel beginning with our first gas sale. Initial gas production will come from Uracoa, which allows us to more efficiently manage the reservoir and eliminate the restrictions on producing oil wells with high gas to oil ratios. The gas reserves in Bombal will beloans were used to meet the future termsSENIAT income tax assessments and related interest, refinance a portion of one of the gas contract in 2005.
S-21
The Venezuelan government maintains full ownership of all hydrocarbons in the fields.
We drilled three oil wellsBolivar loans and converted two gas injection wells to producing wells in 2003.
fund operating requirements.
We acquired a 100 percent interest in three California State offshore oil and gas leases (“California Leases”) and a parcel of onshore property from Molino Energy Company, LLC. All capitalized costs associated with the California Leases have been fully impaired. The California Leases have expired and we have listed the onshore property for sale.
Note 12 -8 — China Operations
We have entered into construction service agreements with Venezolana International, S.A. (“Vinsa”). Vinsa is an affiliate of Venezolana de Inversiones y Construcciones Clerico, C.A., which owns 20 percent of Benton-Vinccler. Vinsa has provided $1.7 million, $0.5 million and $0.6 million in construction services on our Venezuelan gas pipeline and field operations for the years ended December 31, 2003, 2002 and 2001, respectively.
We have
From 1996 through 1998, we made unsecured loans to our then Chief Executive Officer, A. E. Benton, bearing interest at the rate of 6 percent per annum. We subsequently obtained a security interest in Mr. Benton’s shares of our stock and stock options. In August 1999, Mr. Benton filed a chapter 11 (reorganization) bankruptcy petition in the U.S. Bankruptcy Court for the Central District of California, in Santa Barbara, California. In February 2000, we entered into a separation agreement with Mr. Benton pursuant to which we retained Mr. Bentonrespectively, under a consulting agreement to perform certain services for us. In addition, the consulting agreement provided Mr. Benton with incentive bonuses tied to our net cash receipts from the sale of our interests in Arctic Gas and Geoilbent. In June 2002, we made an incentive bonus payment to Mr. Benton of $1.5 million, subject to future adjustment, in connection with the Arctic Gas sale. We recorded the bonus payment as a reduction of the gain on the Arctic Gas sale. In November 2003, we made a payment to Mr. Benton of $0.5 million for the incentive bonus associated with the sale of our minority equity investment in Geoilbent.
In May 2001, we and Mr. Benton entered into a settlement and release agreement under which the consulting agreement was terminated as to future services and Mr. Benton agreed to propose a plan of reorganization in his bankruptcy case that provided for the repayment of our loans to him. In March 2002, Mr. Benton filed a plan of reorganization, and on July 31, 2002, the bankruptcy court confirmed the plan of reorganization. At the time the plan became final, Mr. Benton’s indebtedness to us was about $6.7 million for which we provided a full allowance for bad debt. On August 14, 2002, we exercised our rights with respect to 600,000 shares of our stock pledged to us as partial repayment of the loan and took the shares into our treasury stock. Based on a $3.56 closing price for the stock on that date, the value of the shares was $2.1 million. Also, in September 2002 and July 2003, we received payments of approximately $1.3 million as distributions from Mr.
S-22
Benton’s debtor-in-possession account. Finally, under the terms of the settlement agreement, we have retained about $0.2 million from the Arctic Gas and Geoilbent bonus payments to Mr. Benton, bringing the total recovery on Mr. Benton’s debt to $3.7 million. We continue to accrue interest and provide a bad debt allowance on the remaining amount due. In addition, we hold the rights to direct the exercise of Mr. Benton’s stock options.
We and Mr. Benton disagreed over Mr. Benton’s remaining obligations to us under the settlement agreement and plan of reorganization. In addition, Mr. Benton claimed that he was due significant additional amounts with respect to the incentive bonus associated with the Arctic Gas sale. We and Mr. Benton submitted our dispute to binding arbitration and in October 2003 the arbitrator found in favor of Mr. Benton in all material respects. As a result, in October 2003, we made a payment to Mr. Benton of $1.9 million for the balance of the incentive bonus associated with the Arctic Gas sale and released certain funds for the payment of Mr. Benton’s taxes and expenses related to the disposition of his 600,000 shares of stock.
Note 14 -10 — Earnings Per Share
S-23S-21
Quarter Ended | ||||||||||||||||
March 31 | June 30 | September 30 | December 31 | |||||||||||||
(amounts in thousands, except per share data) | ||||||||||||||||
Year ended December 31, 2003 | ||||||||||||||||
Revenues | $ | 18,825 | $ | 28,576 | $ | 27,834 | $ | 30,860 | ||||||||
Expenses | (13,901 | ) | (19,911 | ) | (20,037 | ) | (18,619 | ) | ||||||||
Non-operating income (expense) | (1,864 | ) | (2,288 | ) | 44,056 | (1,743 | ) | |||||||||
Income from consolidated companies before income taxes and minority interests | 3,060 | 6,377 | 51,853 | 10,498 | ||||||||||||
Income tax expense | 1,056 | 3,104 | 3,603 | 1,894 | ||||||||||||
Income before minority interests | 2,004 | 3,273 | 48,250 | 8,604 | ||||||||||||
Minority interests | 887 | 1,216 | 1,367 | 2,498 | ||||||||||||
Income from consolidated companies | 1,117 | 2,057 | 46,883 | 6,106 | ||||||||||||
Equity in net income (losses) of affiliated companies | (16,575 | ) | (13,470 | ) | (473 | ) | 1,658 | |||||||||
Net income (loss) | $ | (15,458 | ) | $ | (11,413 | ) | $ | 46,410 | $ | 7,764 | ||||||
Other comprehensive income (loss) | 2,614 | (3,001 | ) | 21 | 366 | |||||||||||
Total comprehensive income (loss) | $ | (12,844 | ) | $ | (14,414 | ) | $ | 46,431 | $ | 8,130 | ||||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | (0.44 | ) | $ | (0.32 | ) | $ | 1.31 | $ | 0.22 | ||||||
Diluted | $ | (0.44 | ) | $ | (0.32 | ) | $ | 1.25 | $ | 0.21 | ||||||
Quarter Ended | ||||||||||||||||
March 31 | June 30 | September 30 | December 31 | |||||||||||||
(amounts in thousands, except per share data) | ||||||||||||||||
Year ended December 31, 2002 | ||||||||||||||||
Revenues | $ | 27,247 | $ | 33,022 | $ | 38,841 | $ | 27,621 | ||||||||
Expenses | (18,720 | ) | (35,747 | ) | (17,914 | ) | (19,765 | ) | ||||||||
Non-operating income (expense) | (3,948 | ) | 142,940 | (818 | ) | (2,948 | ) | |||||||||
Income from consolidated companies before income taxes and minority interests | 4,579 | 140,215 | 20,109 | 4,908 | ||||||||||||
Income tax expense (benefit) | 1,801 | 59,692 | 6,612 | (7,810 | ) | |||||||||||
Income before minority interests | 2,778 | 80,523 | 13,497 | 12,718 | ||||||||||||
Minority interests | 1,380 | 2,031 | 2,590 | 3,318 | ||||||||||||
Income from consolidated companies | 1,398 | 78,492 | 10,907 | 9,400 | ||||||||||||
Equity in net income (losses) of affiliated companies | 87 | (2,172 | ) | 1,209 | 1,041 | |||||||||||
Net income | $ | 1,485 | $ | 76,320 | $ | 12,116 | $ | 10,441 | ||||||||
Other comprehensive loss | — | — | (658 | ) | 658 | |||||||||||
Total comprehensive income | 1,485 | 76,320 | 11,458 | 11,099 | ||||||||||||
Net income per common share: | ||||||||||||||||
Basic | $ | 0.04 | $ | 2.20 | $ | 0.35 | $ | 0.30 | ||||||||
Diluted | $ | 0.04 | $ | 2.10 | $ | 0.33 | $ | 0.28 | ||||||||
Quarter Ended | ||||||||||||||||
March 31 | June 30 | September 30 | December 31 | |||||||||||||
(amounts in thousands, except per share data) | ||||||||||||||||
Year ended December 31, 2006 | ||||||||||||||||
Revenues | $ | 59,172 | $ | 334 | $ | — | $ | — | ||||||||
Expenses | (28,143 | ) | (7,796 | ) | (7,654 | ) | (10,414 | ) | ||||||||
Non-operating income (expense) | 1,940 | (13,419 | ) | (2,650 | ) | 258 | ||||||||||
Income before income taxes and minority interests | 32,969 | (20,881 | ) | (10,304 | ) | (10,156 | ) | |||||||||
Income tax expense | 14,762 | 40,810 | 5,338 | 7 | ||||||||||||
Income before minority interests | 18,207 | (61,691 | ) | (15,642 | ) | (10,163 | ) | |||||||||
Minority interests | 4,339 | (11,409 | ) | (2,044 | ) | (1,613 | ) | |||||||||
Net income (loss) | $ | 13,868 | $ | (50,282 | ) | $ | (13,598 | ) | $ | (8,550 | ) | |||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 0.37 | $ | (1.35 | ) | $ | (0.36 | ) | $ | (0.23 | ) | |||||
Diluted | $ | 0.36 | $ | (1.35 | ) | $ | (0.36 | ) | $ | (0.23 | ) | |||||
In the second quarter of 2002, we recognized in non-operating income, the $144.0 million pre-tax gain on the Arctic Gas Sale, and in expense, the write-down of capitalized costs of $13.4 million associated with our WAB-21 offshore China concession.
S-24
Quarter Ended | ||||||||||||||||
March 31 | June 30 | September 30 | December 31 | |||||||||||||
(amounts in thousands, except per share data) | ||||||||||||||||
Year ended December 31, 2005 | ||||||||||||||||
Revenues | $ | 60,986 | $ | 56,442 | $ | 61,221 | $ | 58,292 | ||||||||
Expenses | (27,300 | ) | (26,207 | ) | (32,245 | ) | (31,664 | ) | ||||||||
Non-operating income (expense) | 3,054 | 277 | (1,827 | ) | 2,065 | |||||||||||
Income before income taxes and minority interests | 36,740 | 30,512 | 27,149 | 28,693 | ||||||||||||
Income tax expense | 13,533 | 11,959 | 16,332 | 15,201 | ||||||||||||
Income before minority interests | 23,207 | 18,553 | 10,817 | 13,492 | ||||||||||||
Minority interests | 5,172 | 4,402 | 2,674 | 2,982 | ||||||||||||
Net income | $ | 18,035 | $ | 14,151 | $ | 8,143 | $ | 10,510 | ||||||||
Net income per common share: | ||||||||||||||||
Basic | $ | 0.49 | $ | 0.38 | $ | 0.22 | $ | 0.28 | ||||||||
Diluted | $ | 0.47 | $ | 0.37 | $ | 0.21 | $ | 0.27 | ||||||||
Other comprehensive income (loss) | (6,048 | ) | 1,770 | 2,287 | 1,991 | |||||||||||
Total comprehensive income | $ | 11,987 | $ | 15,921 | $ | 10,430 | $ | 12,501 | ||||||||
Supplemental Information on Oil and Natural Gas Producing Activities (unaudited)
S-22
United States | Venezuela | China | Total | |||||||||||||||||||||||||
Venezuela | China | and Other | Total | |||||||||||||||||||||||||
Year Ended December 31, 2003 | ||||||||||||||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||||||||||||||
Development costs | $ | 58,079 | $ | — | $ | 2 | $ | 58,081 | $ | 501 | $ | — | $ | 501 | ||||||||||||||
Exploration costs | 11 | 39 | 133 | 183 | — | 35 | 35 | |||||||||||||||||||||
$ | 58,090 | $ | 39 | $ | 135 | $ | 58,264 | $ | 501 | $ | 35 | $ | 536 | |||||||||||||||
Year Ended December 31, 2002 | ||||||||||||||||||||||||||||
Year Ended December 31, 2005 | ||||||||||||||||||||||||||||
Development costs | $ | 49,163 | $ | 120 | $ | 577 | $ | 49,860 | $ | 8,912 | $ | — | $ | 8,912 | ||||||||||||||
Exploration costs | 794 | (149 | ) | 88 | 733 | — | 42 | 42 | ||||||||||||||||||||
$ | 49,957 | $ | (29 | ) | $ | 665 | $ | 50,593 | $ | 8,912 | $ | 42 | $ | 8,954 | ||||||||||||||
Year Ended December 31, 2001 | ||||||||||||||||||||||||||||
Acquisition costs | $ | $ | $ | $ | ||||||||||||||||||||||||
Year Ended December 31, 2004 | ||||||||||||||||||||||||||||
Development costs | 35,194 | 77 | 28 | 35,299 | $ | 39,161 | $ | — | $ | 39,161 | ||||||||||||||||||
Exploration costs | 7,694 | — | 909 | 8,603 | 10 | 53 | 63 | |||||||||||||||||||||
$ | 42,888 | $ | 77 | $ | 937 | $ | 43,902 | $ | 39,171 | $ | 53 | $ | 39,224 | |||||||||||||||
United States | Venezuela(a) | China(b) | Total | |||||||||||||||||||||||||
Venezuela | China | and Other | Total | |||||||||||||||||||||||||
December 31, 2003 | ||||||||||||||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||||||||||||||
Proved property costs | $ | 569,055 | $ | 13,401 | $ | — | $ | 582,456 | $ | — | $ | 13,532 | $ | 13,532 | ||||||||||||||
Costs excluded from amortization | — | 2,900 | — | 2,900 | — | 2,900 | 2,900 | |||||||||||||||||||||
Oilfield inventories | 8,266 | — | — | 8,266 | — | — | — | |||||||||||||||||||||
Less accumulated depletion and impairment | (398,206 | ) | (13,401 | ) | — | (411,607 | ) | — | (13,532 | ) | (13,532 | ) | ||||||||||||||||
$ | 179,115 | $ | 2,900 | $ | — | $ | 182,015 | $ | — | $ | 2,900 | $ | 2,900 | |||||||||||||||
December 31, 2002 | ||||||||||||||||||||||||||||
Year Ended December 31, 2005 | ||||||||||||||||||||||||||||
Proved property costs | $ | 519,175 | $ | 26,210 | $ | 21,030 | $ | 566,415 | $ | 617,137 | $ | 13,497 | $ | 630,634 | ||||||||||||||
Costs excluded from amortization | — | 2,900 | — | 2,900 | — | 2,900 | 2,900 | |||||||||||||||||||||
Oilfield inventories | 7,286 | — | — | 7,286 | 8,150 | — | 8,150 | |||||||||||||||||||||
Less accumulated depletion and impairment | (386,824 | ) | (26,210 | ) | (20,764 | ) | (433,798 | ) | (473,496 | ) | (13,497 | ) | (486,993 | ) | ||||||||||||||
$ | 139,637 | $ | 2,900 | $ | 266 | $ | 142,803 | $ | 151,791 | $ | 2,900 | $ | 154,691 | |||||||||||||||
December 31, 2001 | ||||||||||||||||||||||||||||
Year Ended December 31, 2004 | ||||||||||||||||||||||||||||
Proved property costs | $ | 469,218 | $ | 12,892 | $ | 19,813 | $ | 501,923 | $ | 608,225 | $ | 13,454 | $ | 621,679 | ||||||||||||||
Costs excluded from amortization | — | 16,248 | 560 | 16,808 | — | 2,900 | 2,900 | |||||||||||||||||||||
Oilfield inventories | 15,219 | — | — | 15,219 | 6,503 | — | 6,503 | |||||||||||||||||||||
Less accumulated depletion and impairment | (361,313 | ) | (12,892 | ) | (19,544 | ) | (393,749 | ) | (432,302 | ) | (13,454 | ) | (445,756 | ) | ||||||||||||||
$ | 123,124 | $ | 16,248 | $ | 829 | $ | 140,201 | $ | 182,426 | $ | 2,900 | $ | 185,326 | |||||||||||||||
(a) | Reclassified to provisional equity affiliate effective April 1, 2006. | |
(b) | SeeNotes to the Consolidated Financial Statements Note 8 – China Operations. |
S-25S-23
United States | Venezuela | |||||||||||||||||||
Venezuela | China | and Other | Total | |||||||||||||||||
Year ended December 31, 2003 | ||||||||||||||||||||
Oil sales | $ | 106,095 | $ | — | $ | — | $ | 106,095 | ||||||||||||
Year ended December 31, 2006(a) | ||||||||||||||||||||
Oil and natural gas revenues | $ | 59,506 | ||||||||||||||||||
Expenses: | ||||||||||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 31,445 | — | 76 | 31,521 | 9,451 | |||||||||||||||
Write-down of oil and gas properties and impairments | — | 23 | 142 | 165 | ||||||||||||||||
Depletion | 9,904 | |||||||||||||||||||
Income tax expense | 20,076 | |||||||||||||||||||
Total expenses(b) | 39,431 | |||||||||||||||||||
Results of operations from oil and natural gas producing activities | $ | 20,075 | ||||||||||||||||||
Year ended December 31, 2005 | ||||||||||||||||||||
Oil and natural gas revenues | $ | 236,941 | ||||||||||||||||||
Expenses: | ||||||||||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 39,969 | |||||||||||||||||||
Depletion | 19,599 | — | — | 19,599 | 41,175 | |||||||||||||||
Income tax expense | 12,158 | — | 1,187 | 13,345 | 65,943 | |||||||||||||||
Total expenses | 63,202 | 23 | 1,405 | 64,630 | 147,087 | |||||||||||||||
Results of operations from oil and natural gas producing activities | $ | 42,893 | $ | (23 | ) | $ | (1,405 | ) | $ | 41,465 | $ | 89,854 | ||||||||
Year ended December 31, 2002 | ||||||||||||||||||||
Oil sales | $ | 126,731 | $ | — | $ | — | $ | 126,731 | ||||||||||||
Year ended December 31, 2004 | ||||||||||||||||||||
Oil and natural gas revenues | $ | 186,066 | ||||||||||||||||||
Expenses: | ||||||||||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 31,608 | 2,493 | — | 34,101 | 33,297 | |||||||||||||||
Write-down of oil and gas properties and impairments | — | 13,371 | 1,166 | 14,537 | ||||||||||||||||
Depletion | 24,941 | — | — | 24,941 | 34,108 | |||||||||||||||
Income tax expense | 4,715 | 3 | — | 4,718 | 38,968 | |||||||||||||||
Total expenses | 61,264 | 15,867 | 1,166 | 78,297 | 106,373 | |||||||||||||||
Results of operations from oil and natural gas producing activities | $ | 65,467 | $ | (15,867 | ) | (1,166 | ) | 48,434 | $ | 79,693 | ||||||||||
Year ended December 31, 2001 | ||||||||||||||||||||
Oil and natural gas sales | $ | 122,386 | $ | — | $ | — | $ | 122,386 | ||||||||||||
Expenses: | ||||||||||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 42,212 | — | 722 | 42,934 | ||||||||||||||||
Write-down of oil and gas properties and impairments | — | 13 | 455 | 468 | ||||||||||||||||
Depletion | 22,119 | — | — | 22,119 | ||||||||||||||||
Income tax expense | 11,156 | — | 13 | 11,169 | ||||||||||||||||
Total expenses | 75,487 | 13 | 1,190 | 76,690 | ||||||||||||||||
Results of operations from oil and natural gas producing activities | $ | 46,899 | $ | (13 | ) | $ | (1,190 | ) | $ | 45,696 | ||||||||||
(a) | Reflects oil and natural gas deliveries through March 31, 2006. | |
(b) | Excludes taxes of $50.3 million recorded in 2006 due to the settlement of the SENIAT tax assessments. |
April 2006.
S-24
S-26
Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reservesproved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
The 2005 reserve information shown below has been reduced to exclude reserves formerly classified as proved undeveloped. Under SEC standards for the reporting of oil and natural gas reserves, proved reserves are estimated quantities of crude oil and natural gas “which geological data and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirsunder existing economic and operating conditions.” (Emphasis added). Our quantities of proved reserves were reduced to remove undeveloped reserves because the actions taken by the Venezuelan government beginning in 2005 under our OSA have created uncertainty as to whether those reserves will be recovered under the economic and operating conditions which currently exist in Venezuela. For ease of reference, the reclassified reserves are hereafter referred to as “Contractually Restricted Reserves”. In April 2006, the OSA was unilaterally terminated by the Venezuelan government and we are currently awaiting the conversion to Petrodelta. SeeNote 1 – Organization. Until we complete the conversion to Petrodelta, we will not have reserves to report under SEC guidelines and, accordingly, no reserves are reported as of December 31, 2006.
Minority | ||||||||||||
Interest in | ||||||||||||
Venezuela | Venezuela | Net Total | ||||||||||
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) | ||||||||||||
Year ended December 31, 2003 | ||||||||||||
Proved Reserves beginning of the year | 95,168 | (19,033 | ) | 76,135 | ||||||||
Revisions of previous estimates | (521 | ) | 104 | (417 | ) | |||||||
Extensions, discoveries and improved recovery | 572 | (114 | ) | 458 | ||||||||
Production | (7,347 | ) | 1,469 | (5,878 | ) | |||||||
Sales of reserves in place | — | — | — | |||||||||
Proved Reserves at end of the year | 87,872 | (17,574 | ) | 70,298 | ||||||||
Year ended December 31, 2002 | ||||||||||||
Proved Reserves beginning of the year | 104,514 | (20,903 | ) | 83,611 | ||||||||
Revisions of previous estimates | 362 | (72 | ) | 290 | ||||||||
Extensions, discoveries and improved recovery | — | — | — | |||||||||
Production | (9,708 | ) | 1,942 | (7,766 | ) | |||||||
Sales of reserves in place | — | — | — | |||||||||
Proved Reserves at end of the year | 95,168 | (19,033 | ) | 76,135 | ||||||||
Russia – Geoilbent (34%) Proved Reserves at end of the year | 24,781 | |||||||||||
Year ended December 31, 2001 | ||||||||||||
Proved Reserves at beginning of the year | 123,039 | (24,608 | ) | 98,431 | ||||||||
Revisions of previous estimates | (8,747 | ) | 1,749 | (6,998 | ) | |||||||
Purchases of reserves in place | — | — | — | |||||||||
Extensions, discoveries and improved recovery | — | — | — | |||||||||
Production | (9,778 | ) | 1,956 | (7,822 | ) | |||||||
Sales of reserves in place | — | — | — | |||||||||
Proved Reserves at end of the year | 104,514 | (20,903 | ) | 83,611 | ||||||||
Russia – Arctic Gas (39%) Proved Reserves at end of the year | 20,964 | |||||||||||
Russia – Geoilbent (34%) Proved Reserves at end of the year | 29,668 | |||||||||||
S-27S-25
Minority | ||||||||||||
Interest in | ||||||||||||
Venezuela | Venezuela | Net Total | ||||||||||
Proved Developed Reserves at: | ||||||||||||
December 31, 2003 | 45,860 | (9,172 | ) | 36,688 | ||||||||
December 31, 2002 | 53,833 | (10,767 | ) | 43,066 | ||||||||
December 31, 2001 | 51,465 | (10,293 | ) | 41,172 | ||||||||
January 1, 2001 | 67,217 | (13,443 | ) | 53,774 | ||||||||
Russia – Arctic Gas Proved Reserves at end of the year | ||||||||||||
2001 (39%) | 2,483 | |||||||||||
2000 (29%) | 2,325 | |||||||||||
Russia – Geoilbent (34%) Proved Reserves at end of the year | ||||||||||||
2002 | 11,840 | |||||||||||
2001 | 15,658 | |||||||||||
2000 | 14,913 | |||||||||||
Proved Reserves-natural gas (MMcf) | ||||||||||||
Year ended December 31, 2003 | ||||||||||||
Proved Reserves beginning of the year | 198,000 | (39,600 | ) | 158,400 | ||||||||
Revisions of previous estimates | 160 | (32 | ) | 128 | ||||||||
Extensions, discoveries and improved recovery | — | — | — | |||||||||
Production | (2,660 | ) | 532 | (2,128 | ) | |||||||
Proved Reserves end of the year | 195,500 | (39,100 | ) | 156,400 | ||||||||
Year ended December 31, 2002 | ||||||||||||
Proved Reserves beginning of the year | — | — | — | |||||||||
Revisions of previous estimates | — | — | — | |||||||||
Extensions, discoveries and improved recovery | 198,000 | (39,600 | ) | 158,400 | ||||||||
Sales of reserves in place | — | — | — | |||||||||
Proved Reserves end of the year | 198,000 | (39,600 | ) | 158,400 | ||||||||
Russia – Arctic Gas (39%) Proved Reserves – December 31, 2001 | �� | 208,010 | ||||||||||
Russia – Arctic Gas (39%) Proved Reserves – December 31, 2000 | 152,496 | |||||||||||
Proved Developed Reserves at: | ||||||||||||
December 31, 2003 | 106,147 | (21,229 | ) | 84,918 | ||||||||
December 31, 2002 | 105,000 | (21,000 | ) | 84,000 | ||||||||
Russia – Arctic Gas 2001 (39%) | 21,292 | |||||||||||
Russia – Arctic Gas 2000 (29%) | 17,801 |
Minority | ||||||||||||
Interest in | ||||||||||||
Venezuela | Venezuela | Net Total | ||||||||||
(in thousands) | ||||||||||||
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) | ||||||||||||
Year ended December 31, 2006 | ||||||||||||
Proved Reserves at beginning of the year | 35,311 | (7,062 | ) | 28,249 | ||||||||
Revisions of previous estimates(a) | (33,417 | ) | 6,683 | (26,734 | ) | |||||||
Production | (1,894 | ) | 379 | (1,515 | ) | |||||||
Proved Reserves at end of the year | — | — | — | |||||||||
All reserves have been removed pending conversion to |
Year ended December 31, 2005 | ||||||||||||
Proved Reserves at beginning of the year | 78,142 | (15,628 | ) | 62,514 | ||||||||
Revisions of previous estimates(a) | (34,068 | ) | 6,813 | (27,255 | ) | |||||||
Production | (8,763 | ) | 1,753 | (7,010 | ) | |||||||
Proved Developed Reserves at end of the year | 35,311 | (7,062 | ) | 28,249 | ||||||||
(a) | Includes primarily Contractually Restricted Reserves as well as other minor revisions. |
Year ended December 31, 2004 | ||||||||||||
Proved Reserves at beginning of the year | 87,872 | (17,574 | ) | 70,298 | ||||||||
Revisions of previous estimates | (1,578 | ) | 316 | (1,262 | ) | |||||||
Production | (8,152 | ) | 1,630 | (6,522 | ) | |||||||
Proved Reserves at end of the year | 78,142 | (15,628 | ) | 62,514 | ||||||||
Proved Developed Reserves-Crude oil, condensate, and natural gas liquids (MBbls) at: | ||||||||||||
December 31, 2005 | 35,311 | (7,062 | ) | 28,249 | ||||||||
December 31, 2004 | 45,488 | (9,098 | ) | 36,390 | ||||||||
January 1, 2004 | 45,860 | (9,172 | ) | 36,688 |
Year ended December 31, 2006 | ||||||||||||
Proved Reserves beginning of the year | 58,918 | (11,784 | ) | 47,134 | ||||||||
Revisions of previous estimates(a) | (54,412 | ) | 10,883 | (43,529 | ) | |||||||
Production | (4,506 | ) | 901 | (3,605 | ) | |||||||
Proved Reserves end of the year | — | — | — | |||||||||
(a) | All reserves have been removed pending conversion to Petrodelta. |
Year ended December 31, 2005 | ||||||||||||
Proved Reserves beginning of the year | 164,282 | (32,856 | ) | 131,426 | ||||||||
Revisions of previous estimates(a) | (79,687 | ) | 15,937 | (63,750 | ) | |||||||
Production | (25,677 | ) | 5,135 | (20,542 | ) | |||||||
Proved Developed Reserves end of the year | 58,918 | (11,784 | ) | 47,134 | ||||||||
(a) | Includes primarily Contractually Restricted Reserves as well as other minor revisions. |
S-26
Year ended December 31, 2004 | ||||||||||||
Proved Reserves beginning of the year | 195,500 | (39,100 | ) | 156,400 | ||||||||
Revisions of previous estimates | (159 | ) | 32 | (127 | ) | |||||||
Production | (31,059 | ) | 6,212 | (24,847 | ) | |||||||
Proved Reserves end of the year | 164,282 | (32,856 | ) | 131,426 | ||||||||
Proved Developed Reserves-Natural gas (MMcf) at: | ||||||||||||
December 31, 2006 | ||||||||||||
December 31, 2005 | 58,918 | (11,784 | ) | 47,134 | ||||||||
December 31, 2004 | 80,897 | (16,179 | ) | 64,718 | ||||||||
January 1, 2004 | 106,147 | (21,229 | ) | 84,918 |
Minority | ||||||||||||
Interest in | ||||||||||||
Venezuela | Venezuela | Net Total | ||||||||||
(in thousands) | ||||||||||||
December 31, 2005(a) | ||||||||||||
Future cash inflows from sales of oil and gas | $ | 1,029,630 | $ | (205,926 | ) | $ | 823,704 | |||||
Future production costs | (227,079 | ) | 45,416 | (181,663 | ) | |||||||
Future development costs | (27,917 | ) | 5,583 | (22,334 | ) | |||||||
Future income tax expenses | (239,386 | ) | 47,877 | (191,509 | ) | |||||||
Future net cash flows | 535,248 | (107,050 | ) | 428,198 | ||||||||
Effect of discounting net cash flows at 10% | (123,451 | ) | 24,691 | (98,760 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 411,797 | $ | (82,359 | ) | $ | 329,438 | |||||
December 31, 2004 | ||||||||||||
Future cash inflows from sales of oil and gas | $ | 1,852,045 | $ | (370,409 | ) | $ | 1,481,636 | |||||
Future production costs | (342,373 | ) | 68,475 | (273,898 | ) | |||||||
Future development costs | (141,565 | ) | 28,313 | (113,252 | ) | |||||||
Future income tax expenses | (428,833 | ) | 85,767 | (343,066 | ) | |||||||
Future net cash flows | 939,274 | (187,854 | ) | 751,420 | ||||||||
Effect of discounting net cash flows at 10% | (258,049 | ) | 51,609 | (206,440 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 681,225 | $ | (136,245 | ) | $ | 544,980 | |||||
(a) | Proved reserves do not include Contractually Restricted Reserves. |
S-28S-27
Minority | ||||||||||||
Interest in | ||||||||||||
Venezuela | Venezuela | Net Total | ||||||||||
(amounts in thousands) | ||||||||||||
December 31, 2003 | ||||||||||||
Future cash inflow | $ | 1,513,525 | $ | (302,705 | ) | $ | 1,210,820 | |||||
Future production costs | (382,577 | ) | 76,515 | (306,062 | ) | |||||||
Future development costs | (130,160 | ) | 26,032 | (104,128 | ) | |||||||
Future net revenue before income taxes | 1,000,788 | (200,158 | ) | 800,630 | ||||||||
10% annual discount for estimated timing of cash flows | (319,152 | ) | 63,830 | (255,322 | ) | |||||||
Discounted future net cash flows before income taxes | 681,636 | (136,328 | ) | 545,308 | ||||||||
Future income taxes, discounted at 10% per annum | (223,172 | ) | 44,634 | (178,538 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 458,464 | $ | (91,694 | ) | $ | 366,770 | |||||
December 31, 2002 | ||||||||||||
Future cash flows | $ | 1,510,346 | $ | (302,069 | ) | $ | 1,208,277 | |||||
Future production costs | (400,694 | ) | 80,139 | (320,555 | ) | |||||||
Future development costs | (192,671 | ) | 38,534 | (154,137 | ) | |||||||
Future net revenue before income taxes | 916,981 | (183,396 | ) | 733,585 | ||||||||
10% annual discount for estimated timing of cash flows | (315,376 | ) | 63,075 | (252,301 | ) | |||||||
Discounted future net cash flows before income taxes | 601,605 | (120,321 | ) | 481,284 | ||||||||
Future income taxes, discounted at 10% per annum | (204,356 | ) | 40,871 | (163,485 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 397,249 | $ | (79,450 | ) | $ | 317,799 | |||||
Russia – Geoilbent (34%) | $ | 45,395 | ||||||||||
December 31, 2001 | ||||||||||||
Future cash inflow | $ | 1,030,404 | $ | (206,081 | ) | $ | 824,323 | |||||
Future production costs | (558,431 | ) | 111,686 | (446,745 | ) | |||||||
Future development costs | (142,006 | ) | 28,401 | (113,605 | ) | |||||||
Future net revenue before income taxes | 329,967 | (65,994 | ) | 263,973 | ||||||||
10% annual discount for estimated timing of cash flows | (109,704 | ) | 21,941 | (87,763 | ) | |||||||
Discounted future net cash flows before income taxes | 220,263 | (44,053 | ) | 176,210 | ||||||||
Future income taxes, discounted at 10% per annum | (16,103 | ) | 3,221 | (12,882 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 204,160 | $ | (40,832 | ) | $ | 163,328 | |||||
Russia – Arctic Gas (29%) | $ | 82,205 | ||||||||||
Russia – Geoilbent (34%) | $ | 70,648 | ||||||||||
Net Venezuela | ||||||||||||
2006(a) | 2005 | 2004 | ||||||||||
(in thousands) | ||||||||||||
Standardized Measure at January 1 | $ | 329,438 | $ | 544,980 | $ | 366,770 | ||||||
Sales of oil and natural gas, net of related costs | (40,361 | ) | (124,638 | ) | (122,215 | ) | ||||||
Revisions to estimates of proved reserves | ||||||||||||
Net changes in prices, development and production costs | — | 262,852 | 333,237 | |||||||||
Quantities | — | (365,565 | ) | (7,597 | ) | |||||||
Extensions, discoveries and improved recovery, net of future costs | — | — | — | |||||||||
Accretion of discount | — | 80,202 | 54,531 | |||||||||
Net change in income taxes | — | 109,030 | (78,504 | ) | ||||||||
Development costs incurred | 501 | 7,130 | 31,329 | |||||||||
Changes in timing and other | (289,578 | ) | (184,553 | ) | (32,571 | ) | ||||||
Standardized Measure at December 31 | $ | — | $ | 329,438 | $ | 544,980 | ||||||
Net Venezuela | ||||||||||||
2003 | 2002 | 2001 | ||||||||||
(amounts in thousands) | ||||||||||||
Present Value at January 1 | $ | 317,799 | $ | 163,328 | $ | 284,549 | ||||||
Sales of oil and natural gas, net of related costs | (59,720 | ) | (76,098 | ) | (64,139 | ) | ||||||
Revisions to estimates of Proved Reserves | ||||||||||||
Net changes in prices, development and production costs | 76,037 | 310,043 | (141,429 | ) | ||||||||
Quantities | (1,584 | ) | 611 | (26,198 | ) | |||||||
Extensions, discoveries and improved recovery, net of future costs | 4,971 | 89,670 | — | |||||||||
Accretion of discount | 48,128 | 17,621 | 36,846 | |||||||||
Net change in income taxes | (15,053 | ) | (150,603 | ) | 71,033 | |||||||
Development costs incurred | 46,463 | 40,532 | 23,768 | |||||||||
Changes in timing and other | (50,271 | ) | (77,305 | ) | (21,102 | ) | ||||||
Present Value at December 31 | $ | 366,770 | $ | 317,799 | $ | 163,328 | ||||||
S-29
Additional Supplemental Information on Oil and Natural Gas Producing Activities (unaudited) for Russia Equity Affiliates as of September 30, their fiscal year end.
In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on our oil and natural gas exploration and production activities. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on our estimated proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
Geoilbent (34 percent ownership until sold September 25, 2003) and Arctic Gas (39 percent ownership not subject to certain sale and transfer restrictions at December 31, 2001, until Arctic Gas was sold on April 12, 2002, respectively), which are accounted for under the equity method, have been included at their respective ownership interests in the consolidated financial statements based on a fiscal period ending September 30 and, accordingly, results of operations for oil and natural gas producing activities in Russia reflect the years ended September 30, 2002 and 2001.
TABLE I — Total costs incurred in oil and natural gas acquisition, exploration and development activities (in thousands):
Total Equity | ||||||||||||
Arctic Gas | Geoilbent | Affiliates | ||||||||||
Year Ended September 25, 2003 | ||||||||||||
Development costs | $ | — | $ | 3,474 | $ | 3,474 | ||||||
Exploration costs | — | 1,034 | 1,034 | |||||||||
$ | — | $ | 4,508 | $ | 4,508 | |||||||
Year Ended September 30, 2002 | ||||||||||||
Development costs | $ | — | $ | 8,599 | $ | 8,599 | ||||||
Exploration costs | 16,156 | 498 | 16,654 | |||||||||
$ | 16,156 | $ | 9,097 | $ | 25,253 | |||||||
Year Ended September 30, 2001 | ||||||||||||
Development costs | $ | — | $ | 11,483 | $ | 11,483 | ||||||
Exploration costs | 8,136 | 2,074 | 10,210 | |||||||||
$ | 8,136 | $ | 13,557 | $ | 21,693 | |||||||
TABLE II — Capitalized costs related to oil and natural gas producing activities (in thousands):
Total Equity | ||||||||||||
Arctic Gas | Geoilbent | Affiliates | ||||||||||
September 25, 2003 | ||||||||||||
Proved property costs | $ | — | $ | 102,753 | $ | 102,753 | ||||||
Oilfield inventories | — | 2,530 | 2,530 | |||||||||
Less accumulated depletion and impairment | — | (72,333 | ) | (72,333 | ) | |||||||
$ | — | $ | 32,950 | $ | 32,950 | |||||||
September 30, 2002 | ||||||||||||
Proved property costs | $ | — | $ | 94,404 | $ | 94,404 | ||||||
Costs excluded from amortization | — | 272 | 272 | |||||||||
Oilfield inventories | — | 2,348 | 2,348 | |||||||||
Less accumulated depletion and impairment | — | (31,440 | ) | (31,440 | ) | |||||||
$ | — | $ | 65,584 | $ | 65,584 | |||||||
September 30, 2001 | ||||||||||||
Proved property costs | $ | 5,786 | $ | 85,677 | $ | 91,463 | ||||||
Costs excluded from amortization | 11,549 | — | 11,549 | |||||||||
Oilfield inventories | 175 | 4,357 | 4,532 | |||||||||
Less accumulated depletion and impairment | (389 | ) | (22,203 | ) | (22,592 | ) | ||||||
$ | 17,121 | $ | 67,831 | $ | 84,952 | |||||||
S-30
TABLE III — Results of operations for oil and natural gas producing activities (in thousands):
Total Equity | ||||||||||||
Arctic Gas | Geoilbent | Affiliates | ||||||||||
Year ended September 25, 2003 | ||||||||||||
Oil sales | $ | — | $ | 27,876 | $ | 27,876 | ||||||
Expenses: | ||||||||||||
Operating, selling and distribution expenses and taxes other than on income | — | 16,088 | 16,088 | |||||||||
Depletion | — | 6,215 | 6,215 | |||||||||
Write-down of oil and gas properties | — | 32,300 | 32,300 | |||||||||
Income tax expense | — | 2,073 | 2,073 | |||||||||
Total expenses | — | 56,676 | 56,676 | |||||||||
Results of operations from oil and natural gas producing activities | $ | — | $ | (28,800 | ) | $ | (28,800 | ) | ||||
Year ended September 30, 2002 | ||||||||||||
Oil sales | $ | 3,554 | $ | 31,039 | $ | 34,593 | ||||||
Expenses: | ||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 3,102 | 16,902 | 20,004 | |||||||||
Depletion | 139 | 9,237 | 9,376 | |||||||||
Income tax expense | 19 | 1,955 | 1,974 | |||||||||
Total expenses | 3,260 | 28,094 | 31,354 | |||||||||
Results of operations from oil and natural gas producing activities | $ | 294 | $ | 2,945 | $ | 3,239 | ||||||
Year ended September 30, 2001 | ||||||||||||
Oil sales | $ | 4,016 | $ | 34,261 | $ | 38,277 | ||||||
Expenses: | ||||||||||||
Operating, selling and distribution expenses and taxes other than on income | 3,381 | 16,083 | 19,464 | |||||||||
Depletion | 311 | 5,072 | 5,383 | |||||||||
Income tax expense | 80 | 3,742 | 3,822 | |||||||||
Total expenses | 3,772 | 24,897 | 28,669 | |||||||||
Results of operations from oil and natural gas producing activities | $ | 244 | $ | 9,364 | $ | 9,608 | ||||||
TABLE IV — Quantities of Oil and Natural Gas Reserves
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Geoilbent and Arctic Gas oil and gas fields are situated on land belonging to the Government of the Russian Federation. Each obtained licenses from the local authorities and pays unified production taxes to explore and produce oil and gas from these fields. Geoilbent had licenses to develop the North Gubkinskoye and South Tarasovskoye fields in western Siberia. Our 34 percent equity investment in Geoilbent was sold September 25, 2003. Arctic Gas had licenses to develop the Samburg and Yevo-Yakhinskiy fields in western Siberia. Arctic Gas was sold on April 12, 2002.
The SEC requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and we consider such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place.
Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and existing operating methods. This classification includes: a) proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and b) proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well.
S-31
Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Estimates of recoverable reserves for proved undeveloped reserves may be subject to substantial variation and actual recoveries may vary materially from estimates.
Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir.
Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.
Total Equity | ||||||||||||
Arctic Gas | Geoilbent | Affiliates | ||||||||||
Proved Reserves-Crude oil, condensate, and natural gas liquids (MBbls) | ||||||||||||
Year ended September 30, 2003 | ||||||||||||
Proved reserves beginning of the year | — | 25,356 | 25,356 | |||||||||
Revisions of previous estimates | — | 537 | 537 | |||||||||
Extensions, discoveries and improved recovery | — | 962 | 962 | |||||||||
Production | — | (1,942 | ) | (1,942 | ) | |||||||
Sales of reserves in place | — | (24,913 | ) | (24,913 | ) | |||||||
Proved reserves at end of the year | — | — | — | |||||||||
Year ended September 30, 2002 | ||||||||||||
Proved Reserves beginning of the year | 20,965 | 29,668 | 50,633 | |||||||||
Revisions of previous estimates | — | (3,455 | ) | (3,455 | ) | |||||||
Extensions, discoveries and improved recovery | — | 1,493 | 1,493 | |||||||||
Production | (89 | ) | (2,350 | ) | (2,439 | ) | ||||||
Sales of reserves in place | (20,876 | ) | — | (20,876 | ) | |||||||
Proved Reserves at end of the year | — | 25,356 | 25,356 | |||||||||
Year ended September 30, 2001 | ||||||||||||
Proved Reserves beginning of the year | 15,821 | 32,614 | 48,435 | |||||||||
Revisions of previous estimates | 5,327 | (5,594 | ) | (267 | ) | |||||||
Extensions, discoveries and improved recovery | — | 4,411 | 4,411 | |||||||||
Production | (183 | ) | (1,763 | ) | (1,946 | ) | ||||||
Sales of reserves in place | — | — | — | |||||||||
Proved Reserves at end of the year | 20,965 | 29,668 | 50,633 | |||||||||
Proved Developed Reserves at: | ||||||||||||
September 30, 2003 | — | — | — | |||||||||
September 30, 2002 | — | 13,200 | 13,200 | |||||||||
September 30, 2001 | 2,483 | 15,658 | 18,141 | |||||||||
October 1, 2000 | 2,325 | 14,913 | 17,238 | |||||||||
Proved Reserves-natural gas (MMcf) | ||||||||||||
Year ended September 30, 2002 | ||||||||||||
Proved Reserves beginning of the year | 208,010 | — | 208,010 | |||||||||
Revisions of previous estimates | — | — | — | |||||||||
Extensions, discoveries and improved recovery | — | — | — | |||||||||
Production | — | — | — | |||||||||
Sales of reserves in place | (208,010 | ) | — | (208,010 | ) | |||||||
Proved Reserves end of the year | — | — | — | |||||||||
S-32
Total Equity | ||||||||||||
Arctic Gas | Geoilbent | Affiliates | ||||||||||
Year ended September 30, 2001 | ||||||||||||
Proved Reserves beginning of the year | 152,496 | — | 152,496 | |||||||||
Revisions of previous estimates | 55,514 | — | 55,514 | |||||||||
Extensions, discoveries and improved recovery | — | — | — | |||||||||
Production | — | — | — | |||||||||
Sales of reserves in place | — | — | — | |||||||||
Proved Reserves end of the year | 208,010 | — | 208,010 | |||||||||
Proved Developed Reserves at: | ||||||||||||
September 30, 2002 | — | — | — | |||||||||
September 30, 2001 | 21,292 | — | 21,292 | |||||||||
October 1, 2000 | 17,801 | — | 17,801 |
(a) | ||
The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS 69. In preparing this data, assumptions and estimates have been used, and we caution against viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate.
Total Equity | ||||||||||||
Arctic Gas | Geoilbent | Affiliates | ||||||||||
(amounts in thousands) | ||||||||||||
September 30, 2003 | ||||||||||||
Future cash inflow | $ | — | $ | 481,557 | $ | 481,557 | ||||||
Future production costs | — | (229,982 | ) | (229,982 | ) | |||||||
Future development costs | — | (36,666 | ) | (36,666 | ) | |||||||
Future net revenue before income taxes | — | 214,909 | 214,909 | |||||||||
10% annual discount for estimated timing of cash flows | — | (99,948 | ) | (99,948 | ) | |||||||
Discounted future net cash flows before income taxes | — | 114,961 | 114,961 | |||||||||
Future income taxes, discounted at 10% per annum | — | (23,163 | ) | (23,163 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | — | $ | 91,798 | $ | 91,798 | ||||||
September 30, 2002 | ||||||||||||
Future cash inflow | $ | — | $ | 469,837 | $ | 469,837 | ||||||
Future production costs | — | (203,754 | ) | (203,754 | ) | |||||||
Future development costs | — | (40,707 | ) | (40,707 | ) | |||||||
Future net revenue before income taxes | — | 225,376 | 225,376 | |||||||||
10% annual discount for estimated timing of cash flows | — | (108,147 | ) | (108,147 | ) | |||||||
Discounted future net cash flows before income taxes | — | 117,229 | 117,229 | |||||||||
Future income taxes, discounted at 10% per annum | — | (24,290 | ) | (24,290 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | — | $ | 92,939 | $ | 92,939 | ||||||
September 30, 2001 | ||||||||||||
Future cash inflow | $ | 630,340 | $ | 434,348 | $ | 1,064,688 | ||||||
Future production costs | (373,458 | ) | (251,335 | ) | (624,793 | ) | ||||||
Future development costs | (49,139 | ) | (37,020 | ) | (86,159 | ) | ||||||
Future net revenue before income taxes | 207,743 | 145,993 | 353,736 | |||||||||
10% annual discount for estimated timing of cash flows | (99,343 | ) | (64,868 | ) | (164,211 | ) | ||||||
Discounted future net cash flows before income taxes | 108,400 | 81,125 | 189,525 | |||||||||
Future income taxes, discounted at 10% per annum | (26,195 | ) | (10,477 | ) | (36,672 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 82,205 | $ | 70,648 | $ | 152,853 | ||||||
S-33
Equity Affiliates | |||||||||||||||||
2003 | 2002 | 2001 | |||||||||||||||
(amounts in thousands) | |||||||||||||||||
Present Value at October 1 | $ | 92,939 | $ | 152,853 | $ | 171,605 | |||||||||||
Sales of oil and natural gas, net of related costs | (20,410 | ) | (23,644 | ) | (19,001 | ) | |||||||||||
Revisions to estimates of Proved Reserves | |||||||||||||||||
Net changes in prices, development and production costs | (5,522 | ) | 76,545 | (39,880 | ) | ||||||||||||
Quantities | 3,178 | (10,007 | ) | 8,881 | |||||||||||||
Sales of reserves in place | (91,797 | ) | (82,205 | ) | — | ||||||||||||
Extensions, discoveries and improved recovery, net of future costs | 1,245 | 2,031 | 18,767 | ||||||||||||||
Accretion of discount | 11,723 | 7,065 | 21,468 | ||||||||||||||
Net change in income taxes | 1,127 | 1,145 | 6,400 | ||||||||||||||
Development costs incurred | 4,507 | 8,999 | 17,110 | ||||||||||||||
Changes in timing and other | 3,010 | (39,843 | ) | (32,497 | ) | ||||||||||||
Present Value at September 30 | $ | — | $ | 92,939 | $ | 152,853 | |||||||||||
S-34S-28
HARVEST NATURAL RESOURCES, INC. | ||||||
(Registrant) | ||||||
Date: March | 13, 2007 | By: | /s/ | |||
James A. Edmiston | ||||||
Chief Executive Officer | ||||||
Signature | Title | |||
/s/ | Director, President and Chief Executive Officer | |||
/s/ Steven W. TholenSteven W. Tholen | Senior Vice President — Finance, Chief Financial | |||
Officer and Treasurer | ||||
(Principal Financial Officer) | ||||
/s/ Kurt A. Nelson | Vice President-Controller, Chief Accounting Officer | |||
Kurt A. Nelson | ||||
(Principal Accounting Officer) | ||||
S-35
SCHEDULE II
HARVEST NATURAL RESOURCES, INC. AND SUBSIDIARIESValuation and Qualifying Accounts(in thousands)
Additions | ||||||||||||||||||||
Balance at | Charged to | Deductions | Balance at | |||||||||||||||||
Beginning | Charged to | Other | From | End of | ||||||||||||||||
of Year | Income | Accounts | Reserves | Year | ||||||||||||||||
At December 31, 2003 | ||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||
Accounts receivable | $ | 3,525 | $ | 205 | $ | — | $ | 375 | $ | 3,355 | ||||||||||
Deferred tax valuation allowance | 39,146 | 9,219 | — | — | 48,365 | |||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 | |||||||||||||||
At December 31, 2002 | ||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||
Accounts receivable | $ | 6,512 | $ | 289 | $ | — | $ | 3,276 | $ | 3,525 | ||||||||||
Deferred tax valuation allowance | 19,700 | 20,577 | — | 1,131 | 39,146 | |||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 | |||||||||||||||
At December 31, 2001 | ||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||
Accounts receivable | $ | 6,518 | $ | 330 | $ | — | $ | 336 | $ | 6,512 | ||||||||||
Deferred tax valuation allowance | 54,207 | 14,352 | (11,008 | ) | 37,851 | 19,700 | ||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 |
S-36
SCHEDULE III
Financial Statements and Notesfor LLC Geoilbent
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 2003
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-tem liabilities of USD 303 thousand and USD 613 thousand as of 1 October 2002, respectively.
The following table provides pro forma information as if SFAS No. 143 has been applied in previous periods:
Year ended | Year ended | Year ended | ||||||||||
Thousands of US dollars | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||
Asset retirement obligations as of the beginning of the period | 613 | 483 | 358 | |||||||||
Liabilities incurred for the period | 25 | 56 | 79 | |||||||||
Accretion expense | 96 | 75 | 45 | |||||||||
Asset retirement obligations as of the end of the period | 734 | 613 | 483 | |||||||||
Net income for the period as reported | 3,885 | 20,420 | ||||||||||
Pro-forma net income | 3,777 | 20,358 | ||||||||||
Recent accounting standards.FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities(“FIN 46R”), identifies certain off-balance sheet arrangements that meet the definition of a variable interest entity (“VIE”). FIN 46R requires consolidation of VIEs by primary beneficiaries and requires more extensive disclosures. FIN 46R is applicable to any VIE created after 1 February 2003. The Company does not expect the adoption of this interpretation will have any material effect on its financial position or results of operations.
3
LLC 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 concecutive quarters it will result in an event of default whereby the EBRD may, at its option, demand payment of the outstanding principal and interest. As dicussed in Note 4, as of 31 December 2002, 31 March 2003 and 30 June 2003 the Company was in violation of the minimum working capital ratio covenant. As of 30 September 2003, the minimum working capital ratio as defined in the loan facility exceeds the covenant requirements. Additionally, the Company has not completed its implementation of a management information system as required under the terms of the loan. Due to these loan convenant violations, the Company has classified the EBRD debt as a current liability.
In addition, while in default of EBRD covenants, the Company may not declare or pay any dividend, make any distribution on its charter capital, purchase, or redeem any shares of the charter capital of the Company, nor make any payment of principal or interest on subordinated shareholder loans or make any other payment or distribution to any stockholder or any affiliate of any stockholder.
As part of the sale of Harvest’s interest in the Company to YUKOS, as described in Note 1, YUKOS assumed Harvest’s stockholder loan.
Loans from OAO Minley and YUKOS are subordinated, unsecured and repayable commencing from January 2004. Interest rates are 2 percent for the Minley loan, and LIBOR for the YUKOS loan, to January 2004. Repayment of the subordinated loans are subject to approval from the EBRD. If approval is not received, the terms of the loan agreements are not considered to be violated. After January 2004, the interest rates on the YUKOS loan increases to 8 percent for the remainder of 2004, and 12 percent from 2005 onwards.
6
LLC 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:
/s/ Stephen D. Chesebro’Stephen D. Chesebro’ | ||||
Chairman of the Board and Director |
The aggregate maturities of long-term debt outstanding at 30 September 2003 are as follows:
/s/ John U. ClarkeJohn U. Clarke | Director | |||
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:
/s/ H. H. HardeeH. H. Hardee | Director | |||
/s/ Patrick M. MurrayPatrick M. Murray | ||||
Director | ||||
Director |
As a result of the application of EITF No. 92-4 and No. 92-8, the valuation allowance related to property, plant and equipment was reduced to zero and a deferred tax liability of USD 8.1 million recorded on 1 January 2003 (Note 2), with no effect on income as the adjustment was recorded as part of the currency translation adjustment as of 1 January 2003. A subsequent ceiling test writedown in March resulted in the recognition of an additional deferred tax asset of USD 10.8 million of which USD 7.6 million and USD 3.2 million were credited as a deferred tax benefit and an increase to the DTA valuation allowance, respectively.
Deferred income tax assets are classified as follows:
Thousands of US dollars | 30 September 2003 | 30 September 2002 | ||||||
Deferred income tax, current | 966 | 1,806 | ||||||
Deferred income tax, non-current | — | 696 | ||||||
Total net deferred tax asset | 966 | 2,502 | ||||||
9S-29
Additions | ||||||||||||||||||||
Balance at | Charged | Deductions | Balance | |||||||||||||||||
Beginning | Charged to | to Other | From | at End of | ||||||||||||||||
of Year | Income | Accounts | Reserves | Year | ||||||||||||||||
At December 31, 2006 | ||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||
Accounts receivable | $ | 2,757 | $ | — | $ | — | $ | — | $ | 2,757 | ||||||||||
Deferred tax valuation allowance | 27,363 | 5,446 | 32,809 | |||||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 | |||||||||||||||
At December 31, 2005 | ||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||
Accounts receivable | $ | 2,757 | $ | — | $ | — | $ | — | $ | 2,757 | ||||||||||
Deferred tax valuation allowance | 40,492 | (13,129 | ) | — | — | 27,363 | ||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 | |||||||||||||||
At December 31, 2004 | ||||||||||||||||||||
Amounts deducted from applicable assets | ||||||||||||||||||||
Accounts receivable | $ | 3,355 | $ | — | $ | — | $ | 598 | $ | 2,757 | ||||||||||
Deferred tax valuation allowance | 48,365 | (7,873 | ) | — | — | 40,492 | ||||||||||||||
Investment at cost | 1,350 | — | — | — | 1,350 |
Note 14: Taxes (continued)
Taxes other than income tax.The Company is subject to a number of taxes other than on income which are detailed below.
Thousands of US dollars | 30 September 2003 | 30 September 2002 | 30 September 2001 | |||||||||
Export duties | 8,464 | 5,376 | 10,922 | |||||||||
Excise tax | — | 535 | 1,548 | |||||||||
Royalty | — | 2,254 | 4,867 | |||||||||
Mineral restoration tax | 377 | 885 | 4,596 | |||||||||
Road users tax | 203 | 860 | 1,427 | |||||||||
Unified production tax | 19,056 | 14,221 | — | |||||||||
Property taxes | 2,263 | 1,994 | 1,424 | |||||||||
Taxes recovery | (7,017 | ) | — | — | ||||||||
Other taxes | 2,279 | 1,532 | 1,227 | |||||||||
Total taxes other than income tax | 25,625 | 27,657 | 26,011 | |||||||||
Beginning 1 January 2002, mineral restoration tax, royalty tax and excise tax on crude oil production were abolished and replaced by the unified natural resources production tax. From 1 January 2004 through 31 December 2006, the base rate for the unified natural resources production tax is set at RR 347 per metric ton of crude oil produced, and is to be adjusted depending on the market price of Urals blend and the RR/USD exchange rate. The tax becomes nil if the Urals blend price falls to or below USD 8.00 per barrel. From 1 January 2007, the unified natural resources production tax rate is set by law at 16.5 percent of crude oil revenues recognized by the Company based on Tax Regulations of the Russian Federation.
During the year ended 30 September 2003, the Company pursued its claim of overpayment of mineral restoration taxes (MRT) paid during the period from 1999 to 2001 of approximately RR 211 million (USD 7.0 million), plus approximately RR 4 million (USD 0.1 million) in related penalties paid. During the year, the regional courts ruled in favour of the Company and, accordingly, the Company and the tax authorities agreed to offset the amounts awarded against the Company’s unified production taxes payable.
Note 15: Related Party Transactions
As of 30 September 2003 and 2002, the Company had the following balances with its stockholders. These balances are included in the balance sheet within accounts receivable, accounts payable and long-term debt as appropriate.
Thousand of US Dollars | 30 September 2003 | 30 September 2002 | ||||||
Accounts receivable | ||||||||
Purneftegasgeologia and affiliated entities | 19 | 63 | ||||||
Accounts payable | ||||||||
Purneftegasgeologia and affiliated entities | 183 | 574 | ||||||
YUKOS | 2,111 | — | ||||||
Harvest Natural Resources | — | 3,354 | ||||||
Purneftegas and affiliated entities | — | 22 | ||||||
Long-term debt | ||||||||
Harvest Natural Resources | — | 2,500 | ||||||
YUKOS | 2,500 | — | ||||||
Minley | 5,000 | 5,000 |
10S-30
LLC 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
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
EXHIBIT INDEX
3.1 | Amended and Restated Certificate of | |
3.2 | ||
Amended and Restated Bylaws as of | ||
4.1 | Form of Common Stock | |
4.2 | Certificate of Designation, Rights and Preferences of the Series B. Preferred Stock of Benton Oil and Gas Company, filed May 12, 1995. (Incorporated by reference to Exhibit 4.1 to our Form 10-Q filed on May 13, 2002, File No. 1-10762.) | |
4.3 | Second Amended and Restated Rights Agreement, dated as of April 15, 2005, between | |
Operating Service Agreement between Benton Oil and Gas Company and Lagoven, S.A., which has been subsequently combined into PDVSA Petroleo y Gas, S.A., dated July 31, 1992, (portions have been omitted pursuant to Rule 406 promulgated under the Securities Act of 1933 and filed separately with the Securities and Exchange |
Alexander E. Benton Settlement and Release Agreement effective May 11, 2001 (Incorporated by reference to Exhibit 10.27 to our Form 10-Q, filed on August 13, 2001, File No. 1-10762.). | |||
2001 Long Term Stock Incentive | |||
Addendum No. 2 to Operating | |||
10.8† | Indemnification Agreement between Harvest Natural Resources, Inc. and the Directors and Executive Officers of the Company. (Incorporated by reference to Exhibit 10.19 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) | ||
10.9† | Form of 2004 Long Term Stock Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.20 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) | ||
10.10† | Form of 2004 Long Term Stock Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.21 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) | ||
10.11† | Form of 2004 Long Term Stock Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.22 to our Form 10-K filed on February 23, 2005, File No. 1-10762.) |
S-31
10.12 | The Transitory Agreement between Harvest Natural Resources, Inc. and PDVSA Petroleo S.A., dated August 4, 2005. (Incorporated by reference to Exhibit 10.1 to our Form 10-Q filed on | ||
10.13† | Employment Agreement dated | ||
Employment Agreement dated | |||
Employment Agreement dated | |||
10.16† | Employment Agreement dated September 15, 2005 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) | ||
10.17† | Employment Agreement dated September 26, 2005 between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on October 27, 2005, File No. 1-10762.) | ||
10.18† | Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.24 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) | ||
10.19† | Stock Option Agreement dated September 15, 2005, between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.25 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) | ||
10.20† | Stock Option Agreement dated September 26, 2005, between Harvest Natural Resources, Inc. and Byron A. Dunn. (Incorporated by reference to Exhibit 10.26 to our Form 10-K filed on February 27, 2006, File No. 1-10762.) | ||
10.21† | Employment Agreement dated February 10, 2006 between Harvest Natural Resources, Inc. and Kurt A. Nelson. (Incorporated by reference to Exhibit | ||
10.22 | Memorandum of Understanding dated March 31, 2006, between Corporación Venezolana del Petroleo, S.A., PDVSA Petroleo, S.A. and Harvest Vinccler, C.A. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on April 20, 2006, File No. 1-10762.) | ||
10.23 | |||
10.24 | Form of 2006 Long Term Incentive Plan Stock Option Agreement. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) | ||
10.25 | Form of 2006 Long Term Incentive Plan Director Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.3 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) |
S-32
10.26 | Form of 2006 Long Term Incentive Plan Employee Restricted Stock Agreement. (Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) | ||
10.27 | Stock Unit Award Agreement dated September | ||
10.28 | Stock Unit Award Agreement dated March 2, 2006 between Harvest Natural Resources, Inc. and James A. Edmiston. (Incorporated by reference to Exhibit 10.6 to our Form 10-Q filed on August 9, 2006, File No. 1-10762.) | ||
10.29 | Note Payable agreement dated September 28, 2006 between Harvest Vinccler, C.A. and Banco Mercantil, C.A. Banco Universal related to a principal amount of 105 billion Bolivars with interest at 10.02 percent, for financing of the | ||
Vinccler, C.A. and Banco Mercantil, C.A. Banco Universal related to a principal amount of 20 billion Bolivars with interest at 10.02 percent, for financing of the SENIAT assessments. (Incorporated by reference to Exhibit 10.2 to our Form 10-Q filed on October 26, 2006, File No. 1-10762.) | |||
10.31 | Amendment to Original Memorandum of Understanding dated August 16, 2006, between Corporación Venezolana del Petroleo, S.A. and | ||
10.32 | Note Payable agreement dated November 20, 2006 between Harvest Vinccler, C.A. and Banesco Banco Universal C.A. related to a principal amount of 120 billion Bolivars with interest at 10.0 percent, for refinancing of the SENIAT assessments and operating requirements. | ||
10.33 | Form of 2006 Long Term Incentive Plan Stock Option Agreement – Five Year Vesting, Seven Year Term. | ||
21.1 | List of subsidiaries. | ||
23.1 | Consent of PricewaterhouseCoopers LLP | ||
Consent of Ryder Scott Company, LP | |||
31.1 | Certification | ||
31.2 | Certification | ||
32.1 | |||
32.2 | Certification accompanying Annual Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Steven W. Tholen, Senior Vice President, Chief Financial Officer and Treasurer. |
† | Identifies management contracts or compensating plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K. |
S-33