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Delaware | 94-0890210 | 6001 Bollinger Canyon Road, San Ramon, California 94583-2324 | ||
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | (Address of principal executive offices) (Zip Code) |
Title of Each Class | Name of Each Exchange on Which Registered | |
Common stock, par value $.75 per share | New York Stock Exchange, Inc. |
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
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EX-99.1 | ||||||||
INSTANCE DOCUMENT | ||||||||
SCHEMA DOCUMENT | ||||||||
CALCULATION LINKBASE DOCUMENT | ||||||||
LABELS LINKBASE DOCUMENT | ||||||||
PRESENTATION LINKBASE DOCUMENT | ||||||||
DEFINITION LINKBASE DOCUMENT |
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FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
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Item 1. | Business |
(a) | General Development of Business |
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• | Upstream —grow profitably in core areas, build new legacy positions and commercialize the company’s equity natural-gas resource base while growing a high-impact global gas business | |
• | Downstream —improve returns and selectively grow, with a focus on integrated value creation |
• | Invest in peopleto achieve the company’s strategies | |
• | Leverage technologyto deliver superior performance and growth | |
• | Build organizational capabilityto deliver world-class performance in operational excellence, cost management, capital stewardship and profitable growth |
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Components of Oil-Equivalent | ||||||||||||||||||||||||
Crude Oil & Natural Gas | ||||||||||||||||||||||||
Oil-Equivalent (Thousands | Liquids (Thousands of | Natural Gas (Millions of | ||||||||||||||||||||||
of Barrels per Day) | Barrels per Day) | Cubic Feet per Day) | ||||||||||||||||||||||
2008 | 2007 | 2008 | 2007 | 2008 | 2007 | |||||||||||||||||||
United States: | ||||||||||||||||||||||||
California | 215 | 221 | 201 | 205 | 88 | 97 | ||||||||||||||||||
Gulf of Mexico | 160 | 214 | 86 | 118 | 439 | 576 | ||||||||||||||||||
Texas (Onshore) | 149 | 153 | 76 | 77 | 441 | 457 | ||||||||||||||||||
Other States | 147 | 155 | 58 | 60 | 533 | 569 | ||||||||||||||||||
Total United States | 671 | 743 | 421 | 460 | 1,501 | 1,699 | ||||||||||||||||||
Africa: | ||||||||||||||||||||||||
Angola | 154 | 179 | 145 | 171 | 52 | 48 | ||||||||||||||||||
Nigeria | 154 | 129 | 142 | 126 | 72 | 15 | ||||||||||||||||||
Chad | 29 | 32 | 28 | 31 | 5 | 4 | ||||||||||||||||||
Republic of the Congo | 13 | 8 | 11 | 7 | 12 | 7 | ||||||||||||||||||
Democratic Republic of the Congo | 2 | 3 | 2 | 3 | 1 | 2 | ||||||||||||||||||
Total Africa | 352 | 351 | 328 | 338 | 142 | 76 | ||||||||||||||||||
Asia-Pacific: | ||||||||||||||||||||||||
Thailand | 217 | 224 | 67 | 71 | 894 | 916 | ||||||||||||||||||
Partitioned Neutral Zone (PNZ)2 | 106 | 112 | 103 | 109 | 20 | 17 | ||||||||||||||||||
Australia | 96 | 100 | 34 | 39 | 376 | 372 | ||||||||||||||||||
Bangladesh | 71 | 47 | 2 | 2 | 414 | 275 | ||||||||||||||||||
Kazakhstan | 66 | 66 | 41 | 41 | 153 | 149 | ||||||||||||||||||
Azerbaijan | 29 | 61 | 28 | 60 | 7 | 5 | ||||||||||||||||||
Philippines | 26 | 26 | 5 | 5 | 128 | 126 | ||||||||||||||||||
China | 22 | 26 | 19 | 22 | 22 | 22 | ||||||||||||||||||
Myanmar | 15 | 17 | — | — | 89 | 100 | ||||||||||||||||||
Total Asia-Pacific | 648 | 679 | 299 | 349 | 2,103 | 1,982 | ||||||||||||||||||
Indonesia | 235 | 241 | 182 | 195 | 319 | 277 | ||||||||||||||||||
Other International: | ||||||||||||||||||||||||
United Kingdom | 106 | 115 | 71 | 78 | 208 | 220 | ||||||||||||||||||
Denmark | 61 | 63 | 37 | 41 | 142 | 132 | ||||||||||||||||||
Argentina | 44 | 47 | 37 | 39 | 45 | 50 | ||||||||||||||||||
Canada | 37 | 36 | 36 | 35 | 4 | 5 | ||||||||||||||||||
Colombia | 35 | 30 | — | — | 209 | 178 | ||||||||||||||||||
Trinidad and Tobago | 32 | 29 | — | — | 189 | 174 | ||||||||||||||||||
Netherlands | 9 | 4 | 2 | 3 | 40 | 5 | ||||||||||||||||||
Norway | 6 | 6 | 6 | 6 | 1 | 1 | ||||||||||||||||||
Total Other International | 330 | 330 | 189 | 202 | 838 | 765 | ||||||||||||||||||
Total International | 1,565 | 1,601 | 998 | 1,084 | 3,402 | 3,100 | ||||||||||||||||||
Total Consolidated Operations | 2,236 | 2,344 | 1,419 | 1,544 | 4,903 | 4,799 | ||||||||||||||||||
Equity Affiliates3 | 267 | 248 | 230 | 212 | 222 | 220 | ||||||||||||||||||
Total Including Affiliates4 | 2,503 | 2,592 | 1,649 | 1,756 | 5,125 | 5,019 | ||||||||||||||||||
1 Excludes Athabasca oil sands production, net: | 27 | 27 | 27 | 27 | — | — | ||||||||||||||||||
2 Located between Saudi Arabia and Kuwait. | ||||||||||||||||||||||||
3 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil (TCO) in Kazakhstan and Petroboscan, Petroindependiente and Petropiar/Hamaca in Venezuela. | ||||||||||||||||||||||||
4 Volumes include natural gas consumed in operations of 520 million and 498 million cubic feet per day in 2008 and 2007, respectively. |
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Productive2 | Productive2 | |||||||||||||||
Oil Wells | Gas Wells | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
United States: | ||||||||||||||||
California | 25,726 | 23,921 | 188 | 44 | ||||||||||||
Gulf of Mexico | 1,489 | 1,214 | 922 | 701 | ||||||||||||
Other U.S. | 23,729 | 8,460 | 10,587 | 4,824 | ||||||||||||
Total United States | 50,944 | 33,595 | 11,697 | 5,569 | ||||||||||||
Africa | 2,126 | 723 | 17 | 7 | ||||||||||||
Asia-Pacific | 2,479 | 1,150 | 2,468 | 1,560 | ||||||||||||
Indonesia | 7,879 | 7,737 | 203 | 165 | ||||||||||||
Other International | 1,091 | 680 | 275 | 105 | ||||||||||||
Total International | 13,575 | 10,290 | 2,963 | 1,837 | ||||||||||||
Total Consolidated Companies | 64,519 | 43,885 | 14,660 | 7,406 | ||||||||||||
Equity in Affiliates | 1,174 | 413 | 7 | 2 | ||||||||||||
Total Including Affiliates | 65,693 | 44,298 | 14,667 | 7,408 | ||||||||||||
Multiple completion wells included above: | 881 | 549 | 411 | 318 |
1 | Includes wells producing or capable of producing and injection wells temporarily functioning as producing wells. Wells that produce both oil and gas are classified as oil wells. | |
2 | Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company’s fractional interests in gross wells. |
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2008 | 2007 | 2006 | ||||||||||
Liquids* — Millions of barrels | ||||||||||||
Consolidated Companies | 4,735 | 4,665 | 5,294 | |||||||||
Affiliated Companies | 2,615 | 2,422 | 2,512 | |||||||||
Natural Gas — Billions of cubic feet | ||||||||||||
Consolidated Companies | 19,022 | 19,137 | 19,910 | |||||||||
Affiliated Companies | 4,053 | 3,003 | 2,974 | |||||||||
Total Oil-Equivalent — Millions of barrels | ||||||||||||
Consolidated Companies | 7,905 | 7,855 | 8,612 | |||||||||
Affiliated Companies | 3,291 | 2,922 | 3,008 |
* | Crude oil, condensate and natural gas liquids |
(Thousands of Acres)
Developed and | ||||||||||||||||||||||||
Undeveloped2 | Developed2 | Undeveloped | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
United States: | ||||||||||||||||||||||||
California | 138 | 122 | 183 | 176 | 321 | 298 | ||||||||||||||||||
Gulf of Mexico | 2,108 | 1,500 | 1,568 | 1,141 | 3,676 | 2,641 | ||||||||||||||||||
Other U.S. | 3,441 | 2,784 | 4,461 | 2,497 | 7,902 | 5,281 | ||||||||||||||||||
Total United States | 5,687 | 4,406 | 6,212 | 3,814 | 11,899 | 8,220 | ||||||||||||||||||
Africa | 17,686 | 7,710 | 2,487 | 921 | 20,173 | 8,631 | ||||||||||||||||||
Asia-Pacific | 45,429 | 22,447 | 5,937 | 2,649 | 51,366 | 25,096 | ||||||||||||||||||
Indonesia | 8,031 | 5,348 | 383 | 341 | 8,414 | 5,689 | ||||||||||||||||||
Other International | 35,236 | 19,957 | 1,924 | 613 | 37,160 | 20,570 | ||||||||||||||||||
Total International | 106,382 | 55,462 | 10,731 | 4,524 | 117,113 | 59,986 | ||||||||||||||||||
Total Consolidated Companies | 112,069 | 59,868 | 16,943 | 8,338 | 129,012 | 68,206 | ||||||||||||||||||
Equity in Affiliates | 640 | 300 | 259 | 104 | 899 | 404 | ||||||||||||||||||
Total Including Affiliates | 112,709 | 60,168 | 17,202 | 8,442 | 129,911 | 68,610 | ||||||||||||||||||
1 | Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage includes wholly owned interests and the sum of the company’s fractional interests in gross acreage. | |
2 | Developed acreage is spaced or assignable to productive wells. Undeveloped acreage is acreage on which wells have not been drilled or completed to permit commercial production and that may contain undeveloped proved reserves. The gross undeveloped acres that will expire in 2009, 2010 and 2011 if production is not established by certain required dates are 5,707, 8,290 and 4,720, respectively. |
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Wells Drilling | Net Wells Completed1 | |||||||||||||||||||||||||||||||
at 12/31/082 | 2008 | 2007 | 2006 | |||||||||||||||||||||||||||||
Gross | Net | Prod. | Dry | Prod. | Dry | Prod. | Dry | |||||||||||||||||||||||||
United States: | ||||||||||||||||||||||||||||||||
California | 8 | 1 | 533 | — | 620 | — | 600 | — | ||||||||||||||||||||||||
Gulf of Mexico | 44 | 25 | 26 | 3 | 30 | 1 | 34 | 5 | ||||||||||||||||||||||||
Other U.S. | 9 | 8 | 287 | 1 | 225 | 4 | 317 | 6 | ||||||||||||||||||||||||
Total United States | 61 | 34 | 846 | 4 | 875 | 5 | 951 | 11 | ||||||||||||||||||||||||
Africa | 13 | 8 | 33 | — | 43 | — | 45 | 2 | ||||||||||||||||||||||||
Asia-Pacific | 13 | 4 | 203 | 1 | 223 | — | 235 | 1 | ||||||||||||||||||||||||
Indonesia | 2 | 2 | 462 | — | 374 | — | 258 | — | ||||||||||||||||||||||||
Other International | 7 | 2 | 41 | — | 52 | — | 43 | — | ||||||||||||||||||||||||
Total International | 35 | 16 | 739 | 1 | 692 | — | 581 | 3 | ||||||||||||||||||||||||
Total Consolidated Companies | 96 | 50 | 1,585 | 5 | 1,567 | 5 | 1,532 | 14 | ||||||||||||||||||||||||
Equity in Affiliates | 2 | 1 | 16 | — | 3 | — | 13 | — | ||||||||||||||||||||||||
Total Including Affiliates | 98 | 51 | 1,601 | 5 | 1,570 | 5 | 1,545 | 14 | ||||||||||||||||||||||||
1 | Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. | |
2 | Represents wells in the process of drilling, including wells for which drilling was not completed and which were temporarily suspended at the end of 2008. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company’s fractional interests in gross wells. |
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Wells Drilling | Net Wells Completed1,2 | |||||||||||||||||||||||||||||||
at 12/31/083 | 2008 | 2007 | 2006 | |||||||||||||||||||||||||||||
Gross | Net | Prod. | Dry | Prod. | Dry | Prod. | Dry | |||||||||||||||||||||||||
United States: | ||||||||||||||||||||||||||||||||
California | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Gulf of Mexico | 9 | 3 | 8 | 1 | 4 | 7 | 9 | 8 | ||||||||||||||||||||||||
Other U.S. | — | — | — | 1 | — | 1 | 7 | — | ||||||||||||||||||||||||
Total United States | 9 | 3 | 8 | 2 | 4 | 8 | 16 | 8 | ||||||||||||||||||||||||
Africa | 8 | 3 | 2 | 1 | 6 | 2 | 1 | — | ||||||||||||||||||||||||
Asia-Pacific | 4 | 2 | 10 | 1 | 14 | 9 | 18 | 7 | ||||||||||||||||||||||||
Indonesia | — | — | 4 | 1 | 1 | — | 2 | — | ||||||||||||||||||||||||
Other International | 2 | — | 39 | 2 | 41 | 6 | 6 | 3 | ||||||||||||||||||||||||
Total International | 14 | 5 | 55 | 5 | 62 | 17 | 27 | 10 | ||||||||||||||||||||||||
Total Consolidated Companies | 23 | 8 | 63 | 7 | 66 | 25 | 43 | 18 | ||||||||||||||||||||||||
Equity in Affiliates | — | — | — | — | — | — | 1 | — | ||||||||||||||||||||||||
Total Including Affiliates | 23 | 8 | 63 | 7 | 66 | 25 | 44 | 18 | ||||||||||||||||||||||||
1 | 2007 conformed to 2008 presentation. | |
2 | Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. Some exploratory wells are not drilled with the intention of producing from the well bore. In such cases, “completion” refers to the completion of drilling. Further categorization of productive or dry is based on the determination as to whether hydrocarbons in a sufficient quantity were found to justify completion as a producing well, whether or not the well is actually going to be completed as a producer. | |
3 | Represents wells that are in the process of drilling but have been neither abandoned nor completed as of the last day of the year, including wells for which drilling was not completed and which were temporarily suspended at the end of 2008. Does not include wells for which drilling was completed at year-end 2008 and that were reported as suspended wells in Note 20 beginning onpage FS-48. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company’s fractional interests in gross wells. |
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Chevron has production and exploration activities in most of the world’s major hydrocarbon basins. The company’s upstream strategy is to grow profitably in core areas, build new legacy positions and commercialize the company’s equity natural-gas resource base while growing a high-impact global gas business. The map at left indicates Chevron’s primary areas of production and exploration. |
a) | United States |
California: The company has significant production in the San Joaquin Valley. In 2008, average net oil-equivalent production was 215,000 barrels per day, composed of 196,000 barrels of crude oil, 88 million cubic feet of natural gas and 5,000 barrels of natural gas liquids. Approximately 84 percent of the crude-oil production is considered heavy oil (typically with API gravity lower than 22 degrees). |
Gulf of Mexico: Average net oil-equivalent production during 2008 for the company’s combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 160,000 barrels per day. The daily oil-equivalent production comprised 76,000 barrels of crude oil, 439 million cubic feet of natural gas and 10,000 barrels of natural gas liquids. Production levels in 2008 were adversely affected by damage to facilities caused by hurricanes Gustav and Ike in September. At the end of 2008, approximately 50,000 barrels per day of oil-equivalent production remained offline, with restoration of the volumes to occur as repairs to third-party pipelines and producing facilities are completed. |
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• | Big Foot — 60 percent-owned and operated. A successful appraisal well was completed in first quarter 2008. A final appraisal well began drilling in November 2008, and was completed in January 2009. As of late February 2009, evaluation of the drilling results was under way. | |
• | Buckskin — 55 percent-owned and operated. A successful wildcat well was completed in early 2009. | |
• | Jack & St. Malo — 50 percent- and 41 percent-owned and operated interests, respectively. The prospects are being evaluated together due to their relative proximity. Successful appraisal wells were drilled during 2008 at both Jack and St. Malo, bringing the total wells drilled to three at Jack and four at St. Malo. | |
• | Knotty Head — 25 percent-owned and nonoperated working interest. Subsurface studies continued during 2008 at this 2005 discovery, with an appraisal well planned for third quarter 2009. | |
• | Puma — 22 percent-owned and nonoperated working interest. An appraisal well began drilling in late 2008 and was scheduled for completion in second quarter 2009. | |
• | Tubular Bells — 30 percent-owned and nonoperated working interest. An appraisal well was completed in 2008. |
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Angola: Chevron holds company-operated working interests in offshore Blocks 0 and 14 and nonoperated working interests in offshore Block 2 and the onshore Fina Sonangol Texaco (FST) area. Net production from these operations in 2008 averaged 154,000 barrels of oil-equivalent per day. The company operates in areas A and B of the 39 percent-owned Block 0, which averaged 109,000 barrels per day of net liquids production in 2008. The Block 0 concession extends through 2030. Start-up of the Mafumeira Field in Area A of Block 0 is expected in third quarter 2009, with crude-oil production ramping up to the expected maximum total of 35,000 barrels per day in 2011. Two delineation wells were drilled in Area A. One well found commercial quantities of hydrocarbons and was placed into production during the year. The acquisition of seismic data started in late 2008 and is expected to be finalized in 2010. Also in Area A are three gas management projects that are expected to eliminate routine flaring of natural gas by injecting excess natural gas into various reservoirs. |
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Nigeria: Chevron holds a 40 percent interest in 13 concessions predominantly in the onshore and near-offshore region of the Niger Delta. The company operates under a joint-venture arrangement in this region with the Nigerian National Petroleum Corporation (NNPC), which owns a 60 percent interest. The company also owns varying interests in deepwater offshore blocks. In 2008, the company’s net oil-equivalent production in Nigeria averaged 154,000 barrels per day, composed of 142,000 barrels of liquids and 72 million cubic feet of natural gas. In deepwater offshore, initial production occurred in July 2008 at the 68 percent-owned and operated Agbami Field in OML 127 and OML 128. The project is a subsea design, with wells tied back to a floating production, storage and offloading (FPSO) vessel. By year-end 2008, total crude-oil production was averaging approximately 130,000 barrels per day. Maximum total production of crude oil and natural gas liquids of 250,000 barrels per day is expected to be achieved by year-end 2009. The company initially recognized proved undeveloped reserves for Agbami in 2002. A portion of the proved undeveloped reserves was reclassified to proved developed in 2008 at productionstart-up. The total cost for the first phase of |
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Australia: During 2008, the average net oil-equivalent production from Chevron’s interests in Australia was 96,000 barrels per day, composed of 34,000 barrels of liquids and 376 million cubic feet of natural gas. Chevron has a 17 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2008 averaged 25,000 barrels of crude oil and condensate, 374 million cubic feet of natural gas, and 4,000 barrels of LPG. Approximately 70 percent of the natural gas was sold in the form of LNG to major utilities in Japan, South Korea and China, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. In September 2008, a fifth LNG train increased processing and export capacity from approximately 12 million metric tons per year to more than 16 million. Part of the natural gas for these expanded facilities is being supplied from the Angel natural-gas field, which started production in October 2008. Additional supply will be provided by the North Rankin 2 project, for which an investment decision was made in March 2008. The project is scheduled to start production in 2013.Proved undeveloped reserves were booked in prior years and will be reclassified to proved developed upon completion of the project. |
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Azerbaijan: Chevron holds a 10 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which produces crude oil in the Caspian Sea from the Azeri-Chirag-Gunashli (ACG) project. Chevron also has a 9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which transports AIOC production by pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities in Ceyhan, Turkey. (Refer to “Pipelines” under “Transportation Operations” beginning on page 26 for a discussion of the BTC operations.) In 2008, the company’s daily net production from AIOC averaged 29,000 barrels of oil-equivalent. First oil from Phase III of ACG development occurred during the second quarter 2008. Reserves were reclassified to proved developed shortly beforestart-up. In early 2009, total production was averaging about 670,000 barrels per day. The AIOC operations are conducted under a30-year production-sharing contract (PSC) that expires in 2024. Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project, which is being developed in phases. During 2008, Karachaganak net oil-equivalent production averaged 66,000 barrels per day, composed of 41,000 barrels of liquids and 153 million cubic feet of natural gas. In 2008, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines enabled Karachaganak sales of |
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Thailand: Chevron has operated and nonoperated working interests in several different offshore blocks. The company’s net oil-equivalent production in 2008 averaged 217,000 barrels per day, composed of 67,000 barrels of crude oil and condensate and 894 million cubic feet of natural gas. All of the company’s natural gas production is sold to PTT under long-term sales contracts. Operated interests are in Pattani and other fields with ownership interests ranging from 35 percent to 80 percent in Blocks 10 through 13, B12/27, B8/32, 9A, G4/43 and G4/48. Blocks B8/32 and 9A produce crude oil and natural gas from six operating areas, and Blocks 10 through 13 and B12/27 produce crude oil, condensate and natural gas from 16 operating areas. First production from Block G4/43 occurred in first quarter 2008. |
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China: Chevron has one operated and three nonoperated working interests in several areas. Net oil-equivalent production from the nonoperated areas in 2008 averaged 22,000 barrels per day, composed of 19,000 barrels of crude oil and condensate and 22 million cubic feet of natural gas. The company holds a 49 percent operated interest in the Chuandongbei area in the onshore Sichuan Basin, where the company entered into a30-year PSC effective February 2008 to develop natural gas resources. Project plans included two sour-gas purification plants with an aggregate design capacity of 740 million cubic feet per day. A final investment decision was made for the first stage of the project in December 2008, and proved undeveloped reserves were recognized at that time. In the South China Sea, the company has nonoperated working interests of 33 percent in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, 25 percent in the QHD-32-6 Field in Bohai Bay and 16 percent in the unitized and producing BZ25-1 Field in Bohai Bay Block 11/19. Chevron also holds a 50 percent nonoperated working interest in one prospective onshore natural-gas block in the Ordos Basin. |
Partitioned Neutral Zone (PNZ): During 2008, the company negotiated a30-year extension to its agreement with the Kingdom of Saudi Arabia to operate on behalf of the Saudi government its 50 percent interest in the petroleum resources of the onshore area of the PNZ between Saudi Arabia and Kuwait. Under the extension, Chevron has rights to this 50 percent interest in the hydrocarbon resource and pays a royalty and other taxes on the associated volumes produced until 2039. As a result of the contract extension, the company recognized additional proved reserves. During 2008, the company’s average net oil-equivalent production was 106,000 barrels per | ||||
day, composed of 103,000 barrels of crude oil and 20 million cubic feet of natural gas. Steam injection for the second phase of a steamflood pilot project is anticipated to begin in mid-2009. This pilot is a unique application of steam injection into a carbonate reservoir and, if successful, could significantly increase heavy oil recovery. |
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Chevron’s operated interests in Indonesia are managed by several wholly owned subsidiaries, including PT. Chevron Pacific Indonesia (CPI). CPI holds operated interests of 100 percent in the Rokan and Siak PSCs. Other subsidiaries operate four PSCs in the Kutei Basin, located offshore East Kalimantan, and one PSC in the East Ambalat Block, located offshore northeast Kalimantan. These interests range from 80 percent to 100 percent. Chevron also has nonoperated working interests in a joint venture in Block B in the South Natuna Sea and in the NE Madura III Block in the East Java Sea Basin. Chevron’s interests in these PSCs range from 25 percent to 40 percent. |
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e) | Other International Areas |
Argentina: Chevron holds operated interests in several concessions and one exploratory block in the Neuquen and Austral basins. Working interests range from 19 percent to 100 percent. Net oil-equivalent production in 2008 averaged 44,000 barrels per day, composed of 37,000 barrels of crude oil and natural gas liquids and 45 million cubic feet of natural gas. The company also holds a 14 percent interest in the Oleoductos del Valle S.A. pipeline. Brazil: Chevron holds working interests ranging from 30 percent to 52 percent in three deepwater blocks in the Campos Basin. Chevron also holds a 20 percent nonoperated working interest in one block in the Santos Basin. None of these blocks had production in 2008. In Block BC-4, located in the Campos Basin, the company is the operator and has a 52 percent interest in the Frade Field, which is under development as a subsea production design. Proved undeveloped reserves were recorded for the first time in 2005. Partial reclassification to the proved-developed category is scheduled upon productionstart-up in 2009. Estimated maximum total production of 87,000 oil-equivalent barrels per day is anticipated in 2011. The concession that includes the Frade project expires in 2025. In the partner-operated Campos Basin Block BC-20, two areas — 38 percent-owned Papa-Terra and 30 percent-owned Maromba — were retained for development following the end of the exploration phase of this block. Evaluation of design options continued into |
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Canada: Company activities in Canada include nonoperated working interests of 27 percent in the Hibernia and Hebron fields offshore eastern Canada and 20 percent in the Athabasca Oil Sands Project (AOSP), and operated interests of 60 percent in the Ells River “In Situ” Oil Sands Project. Excluding volumes mined at AOSP, average net oil-equivalent production during 2008 was 37,000 barrels per day, composed of 36,000 barrels of crude oil and natural gas liquids and 4 million cubic feet of natural gas. Substantially all of this production was from the Hibernia Field, where a development plan is being formulated for a proposed Hibernia South Extension. At AOSP, the company’s share of mined bitumen (for upgrading into synthetic crude oil) averaged 27,000 barrels per day during 2008. For Hebron, agreements were reached during | ||||
2008 with the provincial government of Newfoundland and Labrador that allow development activities to begin. As of the end of 2008, the company had not recognized proved reserves for this project. |
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Denmark: Chevron has a 15 percent working interest in the partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 15 fields in the Danish North Sea. Net oil-equivalent production in 2008 from DUC averaged 61,000 barrels per day, composed of 37,000 barrels of crude oil and 142 million cubic feet of natural gas. Faroe Islands: Chevron operates and holds a 40 percent interest in five offshore exploratory blocks. During 2008, the company acquired additional2-D seismic data for an area located near the Rosebank/Lochnagar discovery offshore the United Kingdom. Engineering and geological evaluation of the seismic data continued into early 2009. As of the end of 2008, proved reserves had not been recognized. Netherlands: Chevron is the operator and holds interests ranging from 34 percent to 80 percent in nine blocks in the Dutch sector of the North Sea. In 2008, the company’s net oil-equivalent production from the five producing blocks was 9,000 barrels per day, composed of 2,000 barrels of crude oil and 40 million cubic feet of natural gas. |
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December 31, 2008 | ||||||||||||||||||||||
Operable | Refinery Inputs | |||||||||||||||||||||
Locations | Number | Capacity | 2008 | 2007 | 2006 | |||||||||||||||||
Pascagoula | Mississippi | 1 | 330 | 299 | 285 | 337 | ||||||||||||||||
El Segundo | California | 1 | 265 | 263 | 222 | 258 | ||||||||||||||||
Richmond | California | 1 | 243 | 237 | 192 | 224 | ||||||||||||||||
Kapolei | Hawaii | 1 | 54 | 46 | 51 | 50 | ||||||||||||||||
Salt Lake City | Utah | 1 | 45 | 38 | 42 | 39 | ||||||||||||||||
Other1 | 1 | 80 | 8 | 20 | 31 | |||||||||||||||||
Total Consolidated Companies —United States | 6 | 1,017 | 891 | 812 | 939 | |||||||||||||||||
Pembroke | United Kingdom | 1 | 210 | 203 | 212 | 165 | ||||||||||||||||
Cape Town2 | South Africa | 1 | 110 | 75 | 72 | 71 | ||||||||||||||||
Burnaby, B.C. | Canada | 1 | 55 | 36 | 49 | 49 | ||||||||||||||||
Total Consolidated Companies —International | 3 | 375 | 314 | 333 | 285 | |||||||||||||||||
Affiliates3 | Various Locations | 9 | 747 | 653 | 688 | 765 | ||||||||||||||||
Total Including Affiliates— International | 12 | 1,122 | 967 | 1,021 | 1,050 | |||||||||||||||||
Total Including Affiliates —Worldwide | 18 | 2,139 | 1,858 | 1,833 | 1,989 | |||||||||||||||||
1 | Asphalt plant in Perth Amboy, New Jersey. Plant was idled during 2008. | |
2 | Chevron holds 100 percent of the common stock issued by Chevron South Africa (Pty) Limited, which owns the Cape Town Refinery. A consortium of South African partners owns preferred shares ultimately convertible to a 25 percent equity interest in Chevron South Africa (Pty) Limited. None of the preferred shares had been converted as of February 2009. | |
3 | Chevron sold its 31 percent interest in the Nerefco Refinery in the Netherlands in March 2007. During 2008, the company sold its 4 percent ownership interest in a refinery in Abidjan, Côte d’Ivoire, and its 8 percent ownership interest in a refinery in Cameroon, decreasing the company’s combined share of operable capacity by about 5,000 barrels per day. |
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2008 | 2007 | 2006 | ||||||||||
United States | ||||||||||||
Gasolines | 692 | 728 | 712 | |||||||||
Jet Fuel | 274 | 271 | 280 | |||||||||
Gas Oils and Kerosene | 229 | 221 | 252 | |||||||||
Residual Fuel Oil | 127 | 138 | 128 | |||||||||
Other Petroleum Products2 | 91 | 99 | 122 | |||||||||
Total United States | 1,413 | 1,457 | 1,494 | |||||||||
International3 | ||||||||||||
Gasolines | 589 | 581 | 595 | |||||||||
Jet Fuel | 278 | 274 | 266 | |||||||||
Gas Oils and Kerosene | 710 | 730 | 776 | |||||||||
Residual Fuel Oil | 257 | 271 | 324 | |||||||||
Other Petroleum Products2 | 182 | 171 | 166 | |||||||||
Total International | 2,016 | 2,027 | 2,127 | |||||||||
Total Worldwide3 | 3,429 | 3,484 | 3,621 | |||||||||
1 | Includes buy/sell arrangements. Refer to Note 14 on page FS-43. | — | — | 50 | ||||||||||
2 | Principally naphtha, lubricants, asphalt and coke. | |||||||||||||
3 | Includes share of equity affiliates’ sales: | 512 | 492 | 492 |
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Net Mileage1 | ||||
United States: | ||||
Crude Oil2 | 2,886 | |||
Natural Gas | 2,263 | |||
Petroleum Products3 | 6,030 | |||
Total United States | 11,179 | |||
International: | ||||
Crude Oil2 | 700 | |||
Natural Gas | 576 | |||
Petroleum Products3 | 433 | |||
Total International | 1,709 | |||
Worldwide | 12,888 | |||
1 | Partially owned pipelines are included at the company’s equity percentage. | |
2 | Includes gathering lines related to the transportation function. Excludes gathering lines related to U.S. and international production activities. | |
3 | Includes refined products, chemicals and natural gas liquids. |
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U.S. Flag | Foreign Flag | |||||||||||||||
Cargo Capacity | Cargo Capacity | |||||||||||||||
Number | (Millions of Barrels) | Number | (Millions of Barrels) | |||||||||||||
Owned | 3 | 0.8 | 1 | 1.1 | ||||||||||||
Bareboat Chartered | 2 | 0.7 | 18 | 27.1 | ||||||||||||
Time Chartered* | — | — | 17 | 14.6 | ||||||||||||
Total | 5 | 1.5 | 36 | 42.8 |
* | One year or more. |
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28
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29
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Item 1A. | Risk Factors |
30
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Item 1B. | Unresolved Staff Comments |
Item 2. | Properties |
Item 3. | Legal Proceedings |
31
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Item 4. | Submission of Matters to a Vote of Security Holders |
32
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Item 5. | Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Maximum | ||||||||||||||||
Total Number of | Number of Shares | |||||||||||||||
Total Number | Average | Shares Purchased as | that May Yet be | |||||||||||||
of Shares | Price Paid | Part of Publicly | Purchased Under | |||||||||||||
Period | Purchased(1)(2) | per Share | Announced Program | the Program | ||||||||||||
Oct. 1 – Oct. 31, 2008 | 14,185,681 | 67.71 | 14,184,858 | — | ||||||||||||
Nov. 1 – Nov. 30, 2008 | 7,687,933 | 72.46 | 7,665,000 | — | ||||||||||||
Dec. 1 – Dec. 31, 2008 | 6,373,015 | 76.05 | 6,367,989 | — | ||||||||||||
Total Oct. 1 – Dec. 31, 2008 | 28,246,629 | 70.88 | 28,217,847 | (2 | ) | |||||||||||
(1) | Includes 14,339 common shares repurchased during the three-month period ended December 31, 2008, from company employees for required personal income tax withholdings on the exercise of the stock options issued to management and employees under the company’s broad-based employee stock options, long-term incentive plans and former Texaco Inc. stock option plans. Also includes 14,443 shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended December 31, 2008. The October purchases also include approximately 14.2 million shares acquired in an exchange transaction for a U.S. upstream property and cash. |
(2) | In September 2007, the company authorized stock repurchases of up to $15 billion that may be made from time to time at prevailing prices as permitted by securities laws and other requirements and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. As of December 31, 2008, 118,996,749 shares had been acquired under this program for $10.1 billion. |
Item 6. | Selected Financial Data |
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
Item 8. | Financial Statements and Supplementary Data |
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Table of Contents
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
Item 9A. | Controls and Procedures |
(a) | Evaluation of Disclosure Controls and Procedures |
(b) | Management’s Report on Internal Control Over Financial Reporting |
(c) | Changes in Internal Control Over Financial Reporting |
Item 9B. | Other Information |
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Name and Age | Current and Prior Positions (up to five years) | Current Areas of Responsibility | ||||
D.J. O’Reilly | 62 | Chairman of the Board and Chief Executive Officer (since 2000) | Chief Executive Officer | |||
P.J. Robertson | 62 | Vice Chairman of the Board (since 2002) | Policy, Government and Public Affairs; Human Resources | |||
J.E. Bethancourt | 57 | Executive Vice President (since 2003) | Technology; Chemicals; Mining; Health, Environment and Safety | |||
G.L. Kirkland | 58 | Executive Vice President (since 2005) President of Chevron Overseas Petroleum Inc. (2002 to 2004) | Worldwide Exploration and Production Activities and Global Gas Activities, including Natural Gas Trading | |||
J.S. Watson | 52 | Executive Vice President (since 2008) Vice President and President of Chevron International Exploration and Production Company (2005 through 2007) Vice President and Chief Financial Officer (2000 through 2004) | Business Development, Mergers and Acquisitions, Strategic Planning, Project Resources Company, Procurement | |||
M.K. Wirth | 48 | Executive Vice President (since 2006) President of Global Supply and Trading (2004 to 2006) President of Marketing, Asia, Middle East and Africa Marketing Business Unit (2001 to 2004) | Global Refining, Marketing, Lubricants, and Supply and Trading, excluding Natural Gas Trading | |||
P.E. Yarrington | 52 | Vice President and Chief Financial Officer (since 2009) Vice President and Treasurer (2007 through 2008) Vice President, Policy, Government and Public Affairs (2002 to 2007) | Finance | |||
C.A. James | 54 | Vice President and General Counsel (since 2002) | Law |
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36
Item 15. | Exhibits, Financial Statement Schedules |
Page(s) | ||
FS-26 | ||
FS-27 | ||
FS-28 | ||
FS-29 | ||
FS-30 | ||
FS-31 | ||
FS-32 to FS-59 |
Included on page 38 is Schedule II — Valuation and Qualifying Accounts. |
The Exhibit Index on pagesE-1 andE-2 lists the exhibits that are filed as part of this report. |
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Millions of Dollars
Year Ended December 31 | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Employee Termination Benefits: | ||||||||||||
Balance at January 1 | $ | 117 | $ | 28 | $ | 91 | ||||||
Additions (deductions) charged (credited) to expense | (13 | ) | 106 | (21 | ) | |||||||
Payments | (60 | ) | (17 | ) | (42 | ) | ||||||
Balance at December 31 | $ | 44 | $ | 117 | $ | 28 | ||||||
Allowance for Doubtful Accounts: | ||||||||||||
Balance at January 1 | $ | 200 | $ | 217 | $ | 198 | ||||||
Additions charged to expense | 105 | 29 | 61 | |||||||||
Bad debt write-offs | (30 | ) | (46 | ) | (42 | ) | ||||||
Balance at December 31 | $ | 275 | $ | 200 | $ | 217 | ||||||
Deferred Income Tax Valuation Allowance:* | ||||||||||||
Balance at January 1 | $ | 5,949 | $ | 4,391 | $ | 3,249 | ||||||
Additions charged to deferred income tax expense | 2,599 | 1,894 | 1,700 | |||||||||
Deductions credited to goodwill | — | — | (77 | ) | ||||||||
Deductions credited to deferred income tax expense | (1,013 | ) | (336 | ) | (481 | ) | ||||||
Balance at December 31 | $ | 7,535 | $ | 5,949 | $ | 4,391 | ||||||
* | See also Note 16 to the Consolidated Financial Statements beginning onpage FS-45. |
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By | /s/ David J. O’Reilly |
Principal Executive Officers | ||
(and Directors) | Directors | |
/s/David J. O’Reilly David J. O’Reilly, Chairman of the Board and Chief Executive Officer | Samuel H. Armacost* Samuel H. Armacost | |
/s/Peter J. Robertson Peter J. Robertson, Vice Chairman of the Board | Linnet F. Deily* Linnet F. Deily | |
Robert E. Denham* Robert E. Denham | ||
Robert J. Eaton* Robert J. Eaton | ||
Principal Financial Officer /s/Patricia E. Yarrington Patricia E. Yarrington, Vice President and Chief Financial Officer Principal Accounting Officer /s/Mark A. Humphrey Mark A. Humphrey, Vice President and Comptroller | Sam Ginn* Sam Ginn Enrique Hernandez, Jr.* Enrique Hernandez, Jr. Franklyn G. Jenifer* Franklyn G. Jenifer Sam Nunn* Sam Nunn | |
Donald B. Rice* Donald B. Rice | ||
*By: /s/Lydia I. Beebe Lydia I. Beebe, Attorney-in-Fact | Kevin W. Sharer* Kevin W. Sharer | |
Charles R. Shoemate* Charles R. Shoemate | ||
Ronald D. Sugar* Ronald D. Sugar | ||
Carl Ware* Carl Ware |
39
Financial Table of Contents
FS-2
FS-2 | ||
FS-2 | ||
FS-2 | ||
FS-5 | ||
FS-6 | ||
FS-8 | ||
FS-10 | ||
FS-10 | ||
FS-12 | ||
FS-12 | ||
FS-13 | ||
FS-15 | ||
FS-15 | ||
FS-17 | ||
FS-18 | ||
FS-21 | ||
FS-24 |
FS-25
Consolidated Financial Statements | ||
FS-25 | ||
FS-26 | ||
FS-27 | ||
FS-28 | ||
FS-29 | ||
FS-30 | ||
FS-31 |
FS-32
Notes to the Consolidated Financial Statements | ||||
Note 1 | FS-32 | |||
Note 2 | FS-34 | |||
Note 3 | FS-35 | |||
Note 4 | FS-35 | |||
Note 5 | FS-36 | |||
Note 6 | FS-36 | |||
Note 7 | FS-36 | |||
Note 8 | FS-37 | |||
Note 9 | FS-38 | |||
Note 10 | FS-40 | |||
Note 11 | FS-41 | |||
Note 12 | FS-41 | |||
Note 13 | FS-43 | |||
Note 14 | FS-43 | |||
Note 15 | FS-44 | |||
Note 16 | FS-45 | |||
Note 17 | FS-47 | |||
Note 18 | FS-47 | |||
Note 19 | FS-48 | |||
Note 20 | FS-48 | |||
Note 21 | FS-49 | |||
Note 22 | FS-51 | |||
Note 23 | FS-56 | |||
Note 24 | FS-58 | |||
Note 25 | FS-59 | |||
Note 26 | FS-59 | |||
Note 27 | FS-59 | |||
Five-Year Financial Summary | FS-61 | |||
Supplemental Information on Oil and Gas Producing Activities | FS-62 |
FS-1
Table of Contents
Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
Key Financial Results
Millions of dollars, except per-share amounts | 2008 | 2007 | 2006 | ||||||||||
Net Income | $ | 23,931 | $ | 18,688 | $ | 17,138 | |||||||
Per Share Amounts: | |||||||||||||
Net Income – Basic | $ | 11.74 | $ | 8.83 | $ | 7.84 | |||||||
– Diluted | $ | 11.67 | $ | 8.77 | $ | 7.80 | |||||||
Dividends | $ | 2.53 | $ | 2.26 | $ | 2.01 | |||||||
Sales and Other | |||||||||||||
Operating Revenues | $ | 264,958 | $ | 214,091 | $ | 204,892 | |||||||
Return on: | |||||||||||||
Average Capital Employed | 26.6 | % | 23.1 | % | 22.6 | % | |||||||
Average Stockholders’ Equity | 29.2 | % | 25.6 | % | 26.0 | % | |||||||
Income by Major Operating Area
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Upstream – Exploration and Production | |||||||||||||
United States | $ | 7,126 | $ | 4,532 | $ | 4,270 | |||||||
International | 14,584 | 10,284 | 8,872 | ||||||||||
Total Upstream | 21,710 | 14,816 | 13,142 | ||||||||||
Downstream – Refining, Marketing and Transportation | |||||||||||||
United States | 1,369 | 966 | 1,938 | ||||||||||
International | 2,060 | 2,536 | 2,035 | ||||||||||
Total Downstream | 3,429 | 3,502 | 3,973 | ||||||||||
Chemicals | 182 | 396 | 539 | ||||||||||
All Other | (1,390 | ) | (26 | ) | (516 | ) | |||||||
Net Income* | $ | 23,931 | $ | 18,688 | $ | 17,138 | |||||||
*Includes Foreign Currency Effects: | $ 862 | $(352 | ) | $(219 | ) |
Business Environment and Outlook
ments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent and/ or unusual in nature.
FS-2
Table of Contents
The company has been closely monitoring the ongoing uncertainty in financial and credit markets, the rapid decline in crude-oil prices that began in the second half of 2008, and the general contraction of worldwide economic activity. Management is taking these developments into account in the conduct of daily operations and for business planning. The company remains confident of its underlying financial strength to deal with potential problems presented in this environment.
Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude-oil and natural-gas prices are subject to external
factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and business.
Industry price levels for crude oil were volatile during 2008. The spot price for West Texas Intermediate (WTI) crude oil, a benchmark crude, started 2008 at $96 per barrel and peaked at $147 in early July. At the end of the year, the WTI price had fallen to $45 per barrel. As of mid-February 2009, the WTI price was $38 per barrel. The collapse in price during the second half of 2008 was largely driven by a decline in the demand for crude oil that was associated with a significant weakening in world economies. The WTI price averaged $100 per barrel for the full-year 2008, compared with $72 in 2007.
FS-3
Table of Contents
Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
the Henry Hub price was about $5.60 and $4.70 per MCF, respectively. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest.
FS-6. Refer also to the “Selected Operating Data” table on page
FS-10 for a listing of production volumes for each of the three years ending December 31, 2008.)
The company estimates that oil-equivalent production in 2009 will average approximately 2.63 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, price effects on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the scope of company operations, delays in project startups, fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, civil unrest, changing geopolitics, or other disruptions to operations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Most of Chevron’s upstream investment is currently being made outside the United States. Investments in upstream projects generally are made well in advance of the start of the associated production of crude oil and natural gas.
Downstream Earnings for the downstream segment are closely tied to margins on the refining and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and feedstocks for chemical manufacturing. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and by changes in the price of crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product inventory levels, geopolitical events, refinery maintenance programs and disruptions at refineries resulting from unplanned outages that may be due to severe weather or other operational events.
FS-4
Table of Contents
the crude-oil and product-supply functions and the economic returns on invested capital. Profitability can also be affected by the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refinery and distribution network.
Chemicals Earnings in the petrochemicals business are closely tied to global chemical demand, industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to follow crude oil and natural gas price movements, also influence earnings in this segment.
Operating Developments
Upstream
Indonesia Achieved first oil at North Duri Field Area 12, which Chevron operates with a 100 percent interest. Maximum total crude-oil production of 34,000 barrels per day is expected in 2012.
Downstream
FS-5
Table of Contents
Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
Other
Results of Operations
U.S. Upstream – Exploration and Production
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income | $ | 7,126 | $ | 4,532 | $ | 4,270 | |||||||
U.S upstream income of $7.1 billion in 2008 increased $2.6 billion from 2007. Higher average prices for crude oil and natural gas increased earnings by $3.1 billion between periods. Also contributing to the higher earnings were gains of approximately $1 billion on asset sales, including a $600 million gain on an asset-exchange transaction. Partially offsetting these benefits were adverse effects of about $1.6 billion associated with lower oil-equivalent production and higher operating expenses, which included approximately $400 million of expenses resulting from damage to facilities in the Gulf of Mexico caused by hurricanes Gustav and Ike in September.
Net oil-equivalent production in 2008 averaged 671,000 barrels per day, down 9.7 percent and 12.1 percent from 2007 and 2006, respectively. The decrease between 2007 and 2008 was mainly due to normal field declines and the adverse impact of the hurricanes. The decline in 2007 from 2006 was due primarily to normal field declines. The net liquids component of oil-equivalent production for 2008 averaged 421,000 barrels per day, down approximately 8 percent from 2007 and down 9 percent compared with 2006. Net natural gas production averaged 1.5 billion cubic feet per day in 2008, down 12 percent from 2007 and down 17 percent from 2006.
International Upstream – Exploration and Production
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income* | $ | 14,584 | $ | 10,284 | $ | 8,872 | |||||||
*Includes Foreign Currency Effects: | $ 873 | $ (417 | ) | $ (371 | ) |
International upstream income of $14.6 billion in 2008 increased $4.3 billion from 2007. Higher prices for crude oil and natural gas increased earnings by $4.9 billion. Partially offsetting the benefit of higher prices was an impact of about $1.8 billion associated with a reduction of crude-oil sales volumes due to timing of certain cargo liftings and higher depreciation and operating expenses. Foreign currency effects benefited earnings by $873 million in 2008, compared with reductions to earnings of $417 million in 2007 and $371 million in 2006.
FS-6
Table of Contents
Income in 2007 of $10.3 billion increased $1.4 billion from 2006. Earnings in 2007 benefited approximately $1.6 billion from higher prices, primarily for crude oil, and $300 million from increased liftings. Non-recurring income-tax items also benefited earnings between periods. These benefits to income were partially offset by the impact of higher operating and depreciation expenses.
U.S. Downstream – Refining, Marketing and Transportation
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income | $ | 1,369 | $ | 966 | $ | 1,938 | |||||||
U.S downstream earnings of $1.4 billion in 2008 increased about $400 million from 2007 due mainly to improved margins on the sale of refined products and gains on derivative commodity instruments. Operating expenses were higher between periods. Income of $966 million in 2007 decreased nearly $1 billion from 2006. The decline was associated mainly with lower refined-product margins and higher planned and unplanned refinery downtime than a year earlier. Operating expenses were also higher in 2007 than in 2006.
International Downstream – Refining, Marketing and Transportation
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income* | $ | 2,060 | $ | 2,536 | $ | 2,035 | |||||||
*Includes Foreign Currency Effects: | $ 193 | $ 62 | $ 98 |
International downstream income of $2.1 billion in 2008 decreased nearly $500 million from 2007. Earnings in 2007 included gains of approximately $1 billion on the sale of assets, which included an interest in a refinery and marketing assets in the Benelux region of Europe. The $500 million improvement otherwise between years was associated primarily with a benefit from gains on derivative commodity instruments that was only partially offset by the impact of lower margins on the sale of refined products. Foreign currency effects increased earnings by $193 million in 2008, compared with $62 million in 2007. Income in 2007 of $2.5 billion increased $500 million from 2006, largely due to the gains on asset sales. Margins on the sale of refined products in 2007 were up slightly from 2006. Operating expenses were higher, and earnings from the company’s shipping operations were lower.
FS-7
Table of Contents
Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
Refined-product sales volumes were 2.02 million barrels per day in 2008, about 1 percent lower than 2007 due mainly to reduced sales of gas oil and fuel oil. Refined product sales volumes were 2.03 million barrels per day in 2007, about 5 percent lower than 2006. The decline in 2007 was largely due to the impact of asset sales and the accounting-standard change for buy/sell contracts. Excluding the accounting change, sales decreased about 4 percent.
Chemicals
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income* | $ | 182 | $ | 396 | $ | 539 | |||||||
*Includes Foreign Currency Effects: | $ (18 | ) | $ (3 | ) | $ (8 | ) |
The chemicals segment includes the company’s Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem). In 2008, earnings were $182 million, compared with $396 million and $539 million in 2007 and 2006, respectively. Earnings declined in 2008 due to lower sales volumes of commodity chemicals by CPChem. Higher expenses for planned maintenance activities also contributed to the earnings decline. Earnings also declined for the company’s Oronite subsidiary due to lower volumes and higher operating expenses. In 2007, earnings of $396 million decreased $143 million from 2006 due to the impact of lower margins on the sale of commodity chemicals by CPChem that were only partially offset by improved margins on Oronite’s sales of additives for lubricants and fuel.
All Other
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Net Charges* | $ | (1,390 | ) | $ | (26 | ) | $ | (516 | ) | ||||
*Includes Foreign Currency Effects: | $ (186 | ) | $ 6 | $ 62 |
All Other includes mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels and technology companies, and the company’s interest in Dynegy prior to its sale in May 2007.
Consolidated Statement of Income
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Sales and other operating revenues | $ | 264,958 | $ | 214,091 | $ | 204,892 | |||||||
Sales and other operating revenues increased in the comparative periods due mainly to higher prices for crude oil, natural gas and refined products.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income from equity affiliates | $ | 5,366 | $ | 4,144 | $ | 4,255 | |||||||
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Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Other income | $ | 2,681 | $ | 2,669 | $ | 971 | |||||||
Other income of $2.7 billion in 2008 included gains of approximately $1.3 billion on asset sales. Other income of $2.7 billion in 2007 included net gains of $1.7 billion from asset sales and a loss of $245 million on the early redemption of debt. Interest income was approximately $340 million in 2008 and $600 million in both 2007 and 2006. Foreign currency effects benefited other income by $355 million in 2008 while reducing other income by $352 million and $260 million in 2007 and 2006, respectively.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Purchased crude oil and products | $ | 171,397 | $ | 133,309 | $ | 128,151 | |||||||
Crude oil and product purchases in 2008 increased $38.1 billion from 2007 due to higher prices for crude oil, natural gas and refined products. Crude oil and product purchases in 2007 increased more than $5 billion from 2006 due to these same factors.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Operating, selling, general and administrative expenses | $ | 26,551 | $ | 22,858 | $ | 19,717 | |||||||
Operating, selling, general and administrative expenses in 2008 increased approximately $3.7 billion from 2007 primarily due to $1.2 billion of higher costs for employee and contract labor; $800 million of increased costs for materials, services and equipment; $700 million of uninsured losses associated with hurricanes in the Gulf of Mexico in 2008; and an increase of about $300 million for environmental remediation activities. Total expenses were about $3.1 billion higher in 2007 than in 2006. Increases were recorded in a number of categories, including $1.5 billion of higher costs for employee and contract labor.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Exploration expense | $ | 1,169 | $ | 1,323 | $ | 1,364 | |||||||
Exploration expenses in 2008 declined from 2007 due mainly to lower amounts for well write-offs for operations in the United States. Expenses in 2007 were essentially unchanged from 2006.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Depreciation, depletion and amortization | $ | 9,528 | $ | 8,708 | $ | 7,506 | |||||||
Depreciation, depletion and amortization expenses increased in 2008 from 2007 largely due to higher depreciation rates for certain crude oil and natural gas producing fields, reflecting completion of higher-cost development projects and asset-retirement obligations. The increase between 2006 and 2007 reflects an increase in charges related to asset write-downs and higher depreciation rates for certain crude oil and natural gas producing fields worldwide.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Taxes other than on income | $ | 21,303 | $ | 22,266 | $ | 20,883 | |||||||
Taxes other than on income decreased between 2007 and 2008 periods mainly due to lower import duties as a result of the effects of the 2007 sales of the company’s Benelux refining and marketing businesses and a decline in import volumes in the United Kingdom. Taxes other than on income increased between 2006 and 2007 due to higher import duties in the company’s U.K. downstream operations in 2007.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Interest and debt expense | $ | – | $ | 166 | $ | 451 | |||||||
Interest and debt expense decreased significantly in 2008 because all interest-related amounts were being capitalized. Interest and debt expense in 2007 decreased from 2006 primarily due to lower average debt balances and higher amounts of interest capitalized.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income tax expense | $ | 19,026 | $ | 13,479 | $ | 14,838 | |||||||
Effective income tax rates were 44 percent in 2008, 42 percent in 2007 and 46 percent in 2006. Rates were higher between 2007 and 2008 primarily due to a greater proportion of income earned in tax jurisdictions with higher income tax rates. In addition, the 2007 period included a relatively low effective tax rate on the sale of the company’s investment in Dynegy common stock and the sale of downstream assets in Europe. Rates were lower in 2007 compared with 2006 due mainly to the impact of nonrecurring items in 2007 mentioned above and the absence of 2006 charges related to a tax-law change that increased tax rates on upstream operations in the U.K. North Sea and the settlement of a tax claim in Venezuela. Refer also to the discussion of income taxes in Note 16 beginning on page FS-45.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
Selected Operating Data1,2
2008 | 2007 | 2006 | |||||||||||
U.S. Upstream | |||||||||||||
Net Crude Oil and Natural Gas Liquids Production (MBPD) | 421 | 460 | 462 | ||||||||||
Net Natural Gas Production (MMCFPD)3 | 1,501 | 1,699 | 1,810 | ||||||||||
Net Oil-Equivalent Production (MBOEPD) | 671 | 743 | 763 | ||||||||||
Sales of Natural Gas (MMCFPD) | 7,226 | 7,624 | 7,051 | ||||||||||
Sales of Natural Gas Liquids (MBPD) | 159 | 160 | 124 | ||||||||||
Revenues From Net Production | |||||||||||||
Liquids ($/Bbl) | $ | 88.43 | $ | 63.16 | $ | 56.66 | |||||||
Natural Gas ($/MCF) | $ | 7.90 | $ | 6.12 | $ | 6.29 | |||||||
International Upstream | |||||||||||||
Net Crude Oil and Natural Gas Liquids Production (MBPD) | 1,228 | 1,296 | 1,270 | ||||||||||
Net Natural Gas Production (MMCFPD)3 | 3,624 | 3,320 | 3,146 | ||||||||||
Net Oil-Equivalent Production (MBOEPD)4 | 1,859 | 1,876 | 1,904 | ||||||||||
Sales Natural Gas (MMCFPD) | 4,215 | 3,792 | 3,478 | ||||||||||
Sales Natural Gas Liquids (MBPD) | 114 | 118 | 102 | ||||||||||
Revenues From Liftings | |||||||||||||
Liquids ($/Bbl) | $ | 86.51 | $ | 65.01 | $ | 57.65 | |||||||
Natural Gas ($/MCF) | $ | 5.19 | $ | 3.90 | $ | 3.73 | |||||||
Worldwide Upstream | |||||||||||||
Net Oil-Equivalent Production (MBOEPD)3,4 | |||||||||||||
United States | 671 | 743 | 763 | ||||||||||
International | 1,859 | 1,876 | 1,904 | ||||||||||
Total | 2,530 | 2,619 | 2,667 | ||||||||||
U.S. Downstream | |||||||||||||
Gasoline Sales (MBPD)5 | 692 | 728 | 712 | ||||||||||
Other Refined-Product Sales (MBPD) | 721 | 729 | 782 | ||||||||||
Total (MBPD)6 | 1,413 | 1,457 | 1,494 | ||||||||||
Refinery Input (MBPD) | 891 | 812 | 939 | ||||||||||
International Downstream | |||||||||||||
Gasoline Sales (MBPD)5 | 589 | 581 | 595 | ||||||||||
Other Refined-Product Sales (MBPD) | 1,427 | 1,446 | 1,532 | ||||||||||
Total (MBPD)6, 7 | 2,016 | 2,027 | 2,127 | ||||||||||
Refinery Input (MBPD) | 967 | 1,021 | 1,050 | ||||||||||
1 Includes interest in affiliates. | ||||||||||||
2 MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day; | ||||||||||||
MBOEPD = Thousands of barrels of oil-equivalents per day; Bbl = Barrel; | ||||||||||||
MCF = Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet | ||||||||||||
of gas = 1 barrel of oil. | ||||||||||||
3 Includes natural gas consumed in operations (MMCFPD): | ||||||||||||
United States | 70 | 65 | 56 | |||||||||
International | 450 | 433 | 419 | |||||||||
4 Includes other produced volumes (MBPD): | ||||||||||||
Athabasca Oil Sands – Net | 27 | 27 | 27 | |||||||||
Boscan Operating Service Agreement | – | – | 82 | |||||||||
27 | 27 | 109 | ||||||||||
5 Includes branded and unbranded gasoline. | ||||||||||||
6 Includes volumes for buy/sell contracts (MBPD): | ||||||||||||
United States | – | – | 26 | |||||||||
International | – | – | 24 | |||||||||
7 Includes sales of affiliates (MBPD): | 512 | 492 | 492 |
Liquidity and Capital Resources
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unsecured indebtedness at interest rates based on London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2008. In addition, the company has an automatic shelf registration statement that expires in March 2010 for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company. In January 2009, the company’s Board of Directors authorized the issuance of one or more series of notes or debentures in an aggregate amount up to $5 billion for a term not to exceed ten years.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
Capital and Exploratory Expenditures
2008 | 2007 | 2006 | ||||||||||||||||||||||||||||||||||||
Millions of dollars | U.S. | Int’l. | Total | U.S. | Int’l. | Total | U.S. | Int’l. | Total | |||||||||||||||||||||||||||||
Upstream – Exploration and Production | $ | 5,516 | $ | 11,944 | $ | 17,460 | $ | 4,558 | $ | 10,980 | $ | 15,538 | $ | 4,123 | $ | 8,696 | $ | 12,819 | ||||||||||||||||||||
Downstream – Refining, Marketing and Transportation | 2,182 | 2,023 | 4,205 | 1,576 | 1,867 | 3,443 | 1,176 | 1,999 | 3,175 | |||||||||||||||||||||||||||||
Chemicals | 407 | 78 | 485 | 218 | 53 | 271 | 146 | 54 | 200 | |||||||||||||||||||||||||||||
All Other | 618 | 7 | 625 | 768 | 6 | 774 | 403 | 14 | 417 | |||||||||||||||||||||||||||||
Total | $ | 8,723 | $ | 14,052 | $ | 22,775 | $ | 7,120 | $ | 12,906 | $ | 20,026 | $ | 5,848 | $ | 10,763 | $ | 16,611 | ||||||||||||||||||||
Total, Excluding Equity in Affiliates | $ | 8,241 | $ | 12,228 | $ | 20,469 | $ | 6,900 | $ | 10,790 | $ | 17,690 | $ | 5,642 | $ | 9,050 | $ | 14,692 | ||||||||||||||||||||
Worldwide downstream spending in 2009 is estimated at $4.3 billion, with about $2.0 billion for projects in the United States. Capital projects include upgrades to refineries in the United States and South Korea and construction of a gas-to-liquids facility in support of associated upstream projects.
Financial Ratios
Financial Ratios
At December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Current Ratio | 1.1 | 1.2 | 1.3 | ||||||||||
Interest Coverage Ratio | 166.9 | 69.2 | 53.5 | ||||||||||
Debt Ratio | 9.3 | % | 8.6 | % | 12.5 | % | |||||||
Current Ratio – current assets divided by current liabilities. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a Last-In, First-Out basis. At year-end 2008, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $9 billion.
Interest Coverage Ratio – income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. The company’s interest coverage ratio was higher between 2007 and 2008 and between 2006 and 2007, primarily due to higher before-tax income and lower average debt balances in each of the subsequent years.
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies
Direct Guarantee
Millions of dollars | Commitment Expiration by Period | |||||||||||||||||||
2010– | 2012– | After | ||||||||||||||||||
Total | 2009 | 2011 | 2013 | 2013 | ||||||||||||||||
Guarantee of non-consolidated affiliate or joint-venture obligation | $ | 613 | $ | – | $ | – | $ | 76 | $ | 537 | ||||||||||
The company’s guarantee of approximately $600 million is associated with certain payments under a terminal-use agreement entered into by a company affiliate. The terminal is expected to be operational by 2012. Over the approximate 16-year term of the guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate.
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There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of any amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2009 – $6.4 billion; 2010 – $4.0 billion; 2011 – $3.6 billion; 2012 – $1.5 billion; 2013 – $1.3 billion; 2014 and after – $4.3 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $5.1 billion in 2008, $3.7 billion in 2007 and $3.0 billion in 2006.
Contractual Obligations1
Millions of dollars | Payments Due by Period | |||||||||||||||||||
2010– | 2012– | After | ||||||||||||||||||
Total | 2009 | 2011 | 2013 | 2013 | ||||||||||||||||
On Balance Sheet:2 | ||||||||||||||||||||
Short-Term Debt3 | $ | 2,818 | $ | 2,818 | $ | – | $ | – | $ | – | ||||||||||
Long-Term Debt3 | 5,742 | – | 5,061 | 74 | 607 | |||||||||||||||
Noncancelable Capital Lease Obligations | 548 | 97 | 154 | 143 | 154 | |||||||||||||||
Interest | 2,133 | 174 | 322 | 312 | 1,325 | |||||||||||||||
Off-Balance-Sheet: | ||||||||||||||||||||
Noncancelable Operating Lease Obligations | 2,888 | 503 | 835 | 603 | 947 | |||||||||||||||
Throughput and Take-or-Pay Agreements | 15,726 | 5,063 | 5,383 | 1,261 | 4,019 | |||||||||||||||
Other Unconditional Purchase Obligations4 | 5,356 | 1,342 | 2,159 | 1,541 | 314 | |||||||||||||||
1 | Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 22 beginning on page FS-51. | |
2 | Does not include amounts related to the company’s income tax liabilities associated with uncertain tax positions. The company is unable to make reasonable estimates for the periods in which these liabilities may become payable. The company does not expect settlement of such liabilities will have a material effect on its results of operations, consolidated financial position or liquidity in any single period. | |
3 | $5.0 billion of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule above reflects the projected repayment of the entire amounts in the 2010–2011 period. | |
4 | Does not include obligations to purchase the company’s share of natural gas liquids and regasified natural gas associated with operations of the 36.4 percent-owned Angola LNG affiliate. The LNG plant is expected to commence operations in 2012 and is designed to produce 5.2 million metric tons of liquefied natural gas and related natural gas liquids per year. Volumes and prices associated with these purchase obligations are neither fixed nor determinable. |
Financial and Derivative Instruments
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
Factors” in Part I, Item 1A, of the company’s 2008 Annual Report on Form 10-K.
Millions of dollars | 2008 | 2007 | |||||||
Crude Oil | $ | 39 | $ | 29 | |||||
Natural Gas | 5 | 3 | |||||||
Refined Products | 45 | 23 | |||||||
Foreign Currency The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments, forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.
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Transactions With Related Parties
Litigation and Other Contingencies
oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
estimate a reasonable possible loss (or a range of loss).
Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Balance at January 1 | $ | 1,539 | $ | 1,441 | $ | 1,469 | |||||||
Net Additions | 784 | 562 | 366 | ||||||||||
Expenditures | (505 | ) | (464 | ) | (394 | ) | |||||||
Balance at December 31 | $ | 1,818 | $ | 1,539 | $ | 1,441 | |||||||
the company had been identified as a potentially responsible party or otherwise involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The company’s remediation reserve for these sites at year-end 2008 was $120 million. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s consolidated financial position or liquidity.
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reasonably estimated. The liability balance of approximately $9.4 billion for asset retirement obligations at year-end 2008 related primarily to upstream properties.
that could be classified as proved. The effect on exploration expenses in future periods of the $2.1 billion of suspended wells at year-end 2008 is uncertain pending future activities, including normal project evaluation and additional drilling.
Environmental Matters
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
sidered acceptable at the time but now require investigative or remedial work or both to meet current standards.
Critical Accounting Estimates and Assumptions
1. | the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment neces- |
sary to account for highly uncertain matters or the susceptibility of such matters to change; and | |||
2. | the impact of the estimates and assumptions on the company’s financial condition or operating performance is material. |
Besides those meeting these “critical” criteria, the company makes many other accounting estimates and assumptions in preparing its financial statements and related disclosures. Although not associated with “highly uncertain matters,” these estimates and assumptions are also subject to revision as circumstances warrant, and materially different results may sometimes occur.
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and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
dependent upon plan-investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations.
proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.
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of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed of. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.
efits are recognized only if management determines the tax position is “more likely than not” (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 16 beginning on page FS-45. Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, and environmental remediation and tax matters for the three years ended December 31, 2008.
New Accounting Standards
Combinations (FAS 141-R) In December 2007, the FASB issued FAS 141-R, which became effective for business combination transactions having an acquisition date on or after January 1, 2009. This standard requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date to be measured at their respective fair values. It also requires acquisition-related costs, as well as restructuring costs the acquirer expects to incur for which it is not obligated at acquisition date, to be recorded against income rather than included in purchase-price determination. Finally, the standard requires recognition of contingent arrangements at their acquisition-date fair values, with subsequent changes in fair value generally reflected in income.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||||||
equity section of the Consolidated Balance Sheet but separate from the parent’s equity. It also requires the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the Consolidated Statement of Income. Certain changes in a parent’s ownership interest are to be accounted for as equity transactions and when a subsidiary is deconsolidated, any noncontrolling equity investment in the former subsidiary is to be initially measured at fair value. Implementation of FAS 160 will not significantly change the presentation of the company’s Consolidated Statement of Income or Consolidated Balance Sheet.
be expanded to include a tabular representation of the location and fair value amounts of derivative instruments on the balance sheet, fair value gains and losses on the income statement and gains and losses associated with cash flow hedges recognized in earnings and other comprehensive income.
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Quarterly Results and Stock Market Data
Unaudited
2008 | 2007 | ||||||||||||||||||||||||||||||||
Millions of dollars, except per-share amounts | 4th Q | 3rd Q | 2nd Q | 1st Q | 4th Q | 3rd Q | 2nd Q | 1st Q | |||||||||||||||||||||||||
Revenues and Other Income | |||||||||||||||||||||||||||||||||
Sales and other operating revenues1 | $ | 43,145 | $ | 76,192 | $ | 80,962 | $ | 64,659 | $ | 59,900 | $ | 53,545 | $ | 54,344 | $ | 46,302 | |||||||||||||||||
Income from equity affiliates | 886 | 1,673 | 1,563 | 1,244 | 1,153 | 1,160 | 894 | 937 | |||||||||||||||||||||||||
Other income | 1,172 | 1,002 | 464 | 43 | 357 | 468 | 856 | 988 | |||||||||||||||||||||||||
Total Revenues and Other Income | 45,203 | 78,867 | 82,989 | 65,946 | 61,410 | 55,173 | 56,094 | 48,227 | |||||||||||||||||||||||||
Costs and Other Deductions | |||||||||||||||||||||||||||||||||
Purchased crude oil and products | 23,575 | 49,238 | 56,056 | 42,528 | 38,056 | 33,988 | 33,138 | 28,127 | |||||||||||||||||||||||||
Operating expenses | 5,416 | 5,676 | 5,248 | 4,455 | 4,798 | 4,397 | 4,124 | 3,613 | |||||||||||||||||||||||||
Selling, general and administrative expenses | 1,492 | 1,278 | 1,639 | 1,347 | 1,833 | 1,446 | 1,516 | 1,131 | |||||||||||||||||||||||||
Exploration expenses | 338 | 271 | 307 | 253 | 449 | 295 | 273 | 306 | |||||||||||||||||||||||||
Depreciation, depletion and amortization | 2,589 | 2,449 | 2,275 | 2,215 | 2,094 | 2,495 | 2,156 | 1,963 | |||||||||||||||||||||||||
Taxes other than on income1 | 4,547 | 5,614 | 5,699 | 5,443 | 5,560 | 5,538 | 5,743 | 5,425 | |||||||||||||||||||||||||
Interest and debt expense | – | – | – | – | 7 | 22 | 63 | 74 | |||||||||||||||||||||||||
Minority interests | 6 | 32 | 34 | 28 | 35 | 25 | 19 | 28 | |||||||||||||||||||||||||
Total Costs and Other Deductions | 37,963 | 64,558 | 71,258 | 56,269 | 52,832 | 48,206 | 47,032 | 40,667 | |||||||||||||||||||||||||
Income Before Income Tax Expense | 7,240 | 14,309 | 11,731 | 9,677 | 8,578 | 6,967 | 9,062 | 7,560 | |||||||||||||||||||||||||
Income Tax Expense | 2,345 | 6,416 | 5,756 | 4,509 | 3,703 | 3,249 | 3,682 | 2,845 | |||||||||||||||||||||||||
Net Income | $ | 4,895 | $ | 7,893 | $ | 5,975 | $ | 5,168 | $ | 4,875 | $ | 3,718 | $ | 5,380 | $ | 4,715 | |||||||||||||||||
Per-Share of Common Stock | |||||||||||||||||||||||||||||||||
Net Income | |||||||||||||||||||||||||||||||||
– Basic | $ | 2.45 | $ | 3.88 | $ | 2.91 | $ | 2.50 | $ | 2.34 | $ | 1.77 | $ | 2.52 | $ | 2.20 | |||||||||||||||||
– Diluted | $ | 2.44 | $ | 3.85 | $ | 2.90 | $ | 2.48 | $ | 2.32 | $ | 1.75 | $ | 2.52 | $ | 2.18 | |||||||||||||||||
Dividends | $ | 0.65 | $ | 0.65 | $ | 0.65 | $ | 0.58 | $ | 0.58 | $ | 0.58 | $ | 0.58 | $ | 0.52 | |||||||||||||||||
Common Stock Price Range – High2 | $ | 82.20 | $ | 99.08 | $ | 103.09 | $ | 94.61 | $ | 94.86 | $ | 94.84 | $ | 84.24 | $ | 74.95 | |||||||||||||||||
– Low2 | $ | 57.83 | $ | 77.50 | $ | 86.74 | $ | 77.51 | $ | 83.79 | $ | 80.76 | $ | 74.83 | $ | 66.43 | |||||||||||||||||
1 Includes excise, value-added and similar taxes: | $ | 2,080 | $ | 2,577 | $ | 2,652 | $ | 2,537 | $ | 2,548 | $ | 2,550 | $ | 2,609 | $ | 2,414 | |||||||||||||||||
2 End of day price. |
The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 20, 2009, stockholders of record numbered approximately 205,000. There are no restrictions on the company’s ability to pay dividends.
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Management’s Responsibility for Financial Statements
To the Stockholders of Chevron Corporation
Management’s Report on Internal Control Over Financial Reporting
The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on theInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2008.
David J. O’Reilly | Patricia E. Yarrington | Mark A. Humphrey | ||
Chairman of the Board | Vice President | Vice President | ||
and Chief Executive Officer | and Chief Financial Officer | and Comptroller |
February 26, 2009
FS-25
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Chevron Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2008 and December 31, 2007 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008 based on criteria established inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
/s/PricewaterhouseCoopers LLP
San Francisco, California
February 26, 2009
FS-26
Table of Contents
Consolidated Statement of Income
Millions of dollars, except per-share amounts
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Revenues and Other Income | |||||||||||||
Sales and other operating revenues1,2 | $ | 264,958 | $ | 214,091 | $ | 204,892 | |||||||
Income from equity affiliates | 5,366 | 4,144 | 4,255 | ||||||||||
Other income | 2,681 | 2,669 | 971 | ||||||||||
Total Revenues and Other Income | 273,005 | 220,904 | 210,118 | ||||||||||
Costs and Other Deductions | |||||||||||||
Purchased crude oil and products2 | 171,397 | 133,309 | 128,151 | ||||||||||
Operating expenses | 20,795 | 16,932 | 14,624 | ||||||||||
Selling, general and administrative expenses | 5,756 | 5,926 | 5,093 | ||||||||||
Exploration expenses | 1,169 | 1,323 | 1,364 | ||||||||||
Depreciation, depletion and amortization | 9,528 | 8,708 | 7,506 | ||||||||||
Taxes other than on income1 | 21,303 | 22,266 | 20,883 | ||||||||||
Interest and debt expense | – | 166 | 451 | ||||||||||
Minority interests | 100 | 107 | 70 | ||||||||||
Total Costs and Other Deductions | 230,048 | 188,737 | 178,142 | ||||||||||
Income Before Income Tax Expense | 42,957 | 32,167 | 31,976 | ||||||||||
Income Tax Expense | 19,026 | 13,479 | 14,838 | ||||||||||
Net Income | $ | 23,931 | $ | 18,688 | $ | 17,138 | |||||||
Per-Share of Common Stock | |||||||||||||
Net Income | |||||||||||||
– Basic | $ | 11.74 | $ | 8.83 | $ | 7.84 | |||||||
– Diluted | $ | 11.67 | $ | 8.77 | $ | 7.80 | |||||||
1 Includes excise, value-added and similar taxes. | $ | 9,846 | $ | 10,121 | $ | 9,551 | |||||||
2 Includes amounts in revenues for buy/sell contracts; associated costs are in “Purchased crude oil and products.” Refer also to Note 14, on page FS-43. | $ | – | $ | – | $ | 6,725 |
See accompanying Notes to the Consolidated Financial Statements.
FS-27
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Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Net Income | $ | 23,931 | $ | 18,688 | $ | 17,138 | |||||||
Currency translation adjustment | |||||||||||||
Unrealized net change arising during period | (112 | ) | 31 | 55 | |||||||||
Unrealized holding (loss) gain on securities | |||||||||||||
Net (loss) gain arising during period | (6 | ) | 17 | (88 | ) | ||||||||
Reclassification to net income of net realized loss | – | 2 | – | ||||||||||
Total | (6 | ) | 19 | (88 | ) | ||||||||
Derivatives | |||||||||||||
Net derivatives gain (loss) on hedge transactions | 139 | (10 | ) | 2 | |||||||||
Reclassification to net income of net realized loss | 32 | 7 | 95 | ||||||||||
Income taxes on derivatives transactions | (61 | ) | (3 | ) | (30 | ) | |||||||
Total | 110 | (6 | ) | 67 | |||||||||
Defined benefit plans | |||||||||||||
Minimum pension liability adjustment | – | – | (88 | ) | |||||||||
Actuarial loss | |||||||||||||
Amortization to net income of net actuarial loss | 483 | 356 | – | ||||||||||
Actuarial (loss) gain arising during period | (3,228 | ) | 530 | – | |||||||||
Prior service cost | |||||||||||||
Amortization to net income of net prior service credits | (64 | ) | (15 | ) | – | ||||||||
Prior service (credit) cost arising during period | (32 | ) | 204 | – | |||||||||
Defined benefit plans sponsored by equity affiliates | (97 | ) | 19 | – | |||||||||
Income taxes on defined benefit plans | 1,037 | (409 | ) | 50 | |||||||||
Total | (1,901 | ) | 685 | (38 | ) | ||||||||
Other Comprehensive (Loss) Gain, Net of Tax | (1,909 | ) | 729 | (4 | ) | ||||||||
Comprehensive Income | $ | 22,022 | $ | 19,417 | $ | 17,134 | |||||||
See accompanying Notes to the Consolidated Financial Statements.
FS-28
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At December 31 | |||||||||
2008 | 2007 | ||||||||
Assets | |||||||||
Cash and cash equivalents | $ | 9,347 | $ | 7,362 | |||||
Marketable securities | 213 | 732 | |||||||
Accounts and notes receivable (less allowance: 2008 – $246; 2007 – $165) | 15,856 | 22,446 | |||||||
Inventories: | |||||||||
Crude oil and petroleum products | 5,175 | 4,003 | |||||||
Chemicals | 459 | 290 | |||||||
Materials, supplies and other | 1,220 | 1,017 | |||||||
Total inventories | 6,854 | 5,310 | |||||||
Prepaid expenses and other current assets | 4,200 | 3,527 | |||||||
Total Current Assets | 36,470 | 39,377 | |||||||
Long-term receivables, net | 2,413 | 2,194 | |||||||
Investments and advances | 20,920 | 20,477 | |||||||
Properties, plant and equipment, at cost | 173,299 | 154,084 | |||||||
Less: Accumulated depreciation, depletion and amortization | 81,519 | 75,474 | |||||||
Properties, plant and equipment, net | 91,780 | 78,610 | |||||||
Deferred charges and other assets | 4,711 | 3,491 | |||||||
Goodwill | 4,619 | 4,637 | |||||||
Assets held for sale | 252 | – | |||||||
Total Assets | $ | 161,165 | $ | 148,786 | |||||
Liabilities and Stockholders’ Equity | |||||||||
Short-term debt | $ | 2,818 | $ | 1,162 | |||||
Accounts payable | 16,580 | 21,756 | |||||||
Accrued liabilities | 8,077 | 5,275 | |||||||
Federal and other taxes on income | 3,079 | 3,972 | |||||||
Other taxes payable | 1,469 | 1,633 | |||||||
Total Current Liabilities | 32,023 | 33,798 | |||||||
Long-term debt | 5,742 | 5,664 | |||||||
Capital lease obligations | 341 | 406 | |||||||
Deferred credits and other noncurrent obligations | 17,678 | 15,007 | |||||||
Noncurrent deferred income taxes | 11,539 | 12,170 | |||||||
Reserves for employee benefit plans | 6,725 | 4,449 | |||||||
Minority interests | 469 | 204 | |||||||
Total Liabilities | 74,517 | 71,698 | |||||||
Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued) | – | – | |||||||
Common stock (authorized 6,000,000,000 shares at December 31, 2008, and 4,000,000,000 at December 31, 2007; $0.75 par value; 2,442,676,580 shares issued at December 31, 2008 and 2007) | 1,832 | 1,832 | |||||||
Capital in excess of par value | 14,448 | 14,289 | |||||||
Retained earnings | 101,102 | 82,329 | |||||||
Notes receivable – key employees | – | (1 | ) | ||||||
Accumulated other comprehensive loss | (3,924 | ) | (2,015 | ) | |||||
Deferred compensation and benefit plan trust | (434 | ) | (454 | ) | |||||
Treasury stock, at cost (2008 – 438,444,795 shares; 2007 – 352,242,618 shares) | (26,376 | ) | (18,892 | ) | |||||
Total Stockholders’ Equity | 86,648 | 77,088 | |||||||
Total Liabilities and Stockholders’ Equity | $ | 161,165 | $ | 148,786 | |||||
See accompanying Notes to the Consolidated Financial Statements.
FS-29
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Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Operating Activities | |||||||||||||
Net income | $ | 23,931 | $ | 18,688 | $ | 17,138 | |||||||
Adjustments | |||||||||||||
Depreciation, depletion and amortization | 9,528 | 8,708 | 7,506 | ||||||||||
Dry hole expense | 375 | 507 | 520 | ||||||||||
Distributions less than income from equity affiliates | (440 | ) | (1,439 | ) | (979 | ) | |||||||
Net before-tax gains on asset retirements and sales | (1,358 | ) | (2,315 | ) | (229 | ) | |||||||
Net foreign currency effects | (355 | ) | 378 | 259 | |||||||||
Deferred income tax provision | 598 | 261 | 614 | ||||||||||
Net (increase) decrease in operating working capital | (1,673 | ) | 685 | 1,044 | |||||||||
Minority interest in net income | 100 | 107 | 70 | ||||||||||
Increase in long-term receivables | (161 | ) | (82 | ) | (900 | ) | |||||||
(Increase) decrease in other deferred charges | (84 | ) | (530 | ) | 232 | ||||||||
Cash contributions to employee pension plans | (839 | ) | (317 | ) | (449 | ) | |||||||
Other | 10 | 326 | (503 | ) | |||||||||
Net Cash Provided by Operating Activities | 29,632 | 24,977 | 24,323 | ||||||||||
Investing Activities | |||||||||||||
Capital expenditures | (19,666 | ) | (16,678 | ) | (13,813 | ) | |||||||
Repayment of loans by equity affiliates | 179 | 21 | 463 | ||||||||||
Proceeds from asset sales | 1,491 | 3,338 | 989 | ||||||||||
Net sales of marketable securities | 483 | 185 | 142 | ||||||||||
Net sales (purchases) of other short-term investments | 432 | (799 | ) | – | |||||||||
Net Cash Used for Investing Activities | (17,081 | ) | (13,933 | ) | (12,219 | ) | |||||||
Financing Activities | |||||||||||||
Net borrowings (payments) of short-term obligations | 2,647 | (345 | ) | (677 | ) | ||||||||
Repayments of long-term debt and other financing obligations | (965 | ) | (3,343 | ) | (2,224 | ) | |||||||
Proceeds from issuances of long-term debt | – | 650 | – | ||||||||||
Cash dividends – common stock | (5,162 | ) | (4,791 | ) | (4,396 | ) | |||||||
Dividends paid to minority interests | (99 | ) | (77 | ) | (60 | ) | |||||||
Net purchases of treasury shares | (6,821 | ) | (6,389 | ) | (4,491 | ) | |||||||
Net Cash Used for Financing Activities | (10,400 | ) | (14,295 | ) | (11,848 | ) | |||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | (166 | ) | 120 | 194 | |||||||||
Net Change in Cash and Cash Equivalents | 1,985 | (3,131 | ) | 450 | |||||||||
Cash and Cash Equivalents at January 1 | 7,362 | 10,493 | 10,043 | ||||||||||
Cash and Cash Equivalents at December 31 | $ | 9,347 | $ | 7,362 | $ | 10,493 | |||||||
See accompanying Notes to the Consolidated Financial Statements.
FS-30
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Consolidated Statement of Stockholders’ Equity
2008 | 2007 | 2006 | |||||||||||||||||||||||
Shares | Amount | Shares | Amount | Shares | Amount | ||||||||||||||||||||
Preferred Stock | – | $ | – | – | $ | – | – | $ | – | ||||||||||||||||
Common Stock | |||||||||||||||||||||||||
Balance at January 1 | 2,442,677 | $ | 1,832 | 2,442,677 | $ | 1,832 | 2,442,677 | $ | 1,832 | ||||||||||||||||
Balance at December 31 | 2,442,677 | $ | 1,832 | 2,442,677 | $ | 1,832 | 2,442,677 | $ | 1,832 | ||||||||||||||||
Capital in Excess of Par | |||||||||||||||||||||||||
Balance at January 1 | $ | 14,289 | $ | 14,126 | $ | 13,894 | |||||||||||||||||||
Treasury stock transactions | 159 | 163 | 232 | ||||||||||||||||||||||
Balance at December 31 | $ | 14,448 | $ | 14,289 | $ | 14,126 | |||||||||||||||||||
Retained Earnings | |||||||||||||||||||||||||
Balance at January 1 | $ | 82,329 | $ | 68,464 | $ | 55,738 | |||||||||||||||||||
Net income | 23,931 | 18,688 | 17,138 | ||||||||||||||||||||||
Cash dividends on common stock | (5,162 | ) | (4,791 | ) | (4,396 | ) | |||||||||||||||||||
Adoption of EITF 04-6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” | – | – | (19 | ) | |||||||||||||||||||||
Adoption of FIN 48, “Accounting for Uncertainty in Income Taxes” | – | (35 | ) | – | |||||||||||||||||||||
Tax benefit from dividends paid on unallocated ESOP shares and other | 4 | 3 | 3 | ||||||||||||||||||||||
Balance at December 31 | $ | 101,102 | $ | 82,329 | $ | 68,464 | |||||||||||||||||||
Notes Receivable – Key Employees | $ | – | $ | (1 | ) | $ | (2 | ) | |||||||||||||||||
Accumulated Other Comprehensive Loss | |||||||||||||||||||||||||
Currency translation adjustment Balance at January 1 | $ | (59 | ) | $ | (90 | ) | $ | (145 | ) | ||||||||||||||||
Change during year | (112 | ) | 31 | 55 | |||||||||||||||||||||
Balance at December 31 | $ | (171 | ) | $ | (59 | ) | $ | (90 | ) | ||||||||||||||||
Pension and other postretirement benefit plans Balance at January 1 | $ | (2,008 | ) | $ | (2,585 | ) | $ | (344 | ) | ||||||||||||||||
Change to defined benefit plans during year | (1,901 | ) | 685 | (38 | ) | ||||||||||||||||||||
Adoption of FAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” | – | (108 | ) | (2,203 | ) | ||||||||||||||||||||
Balance at December 31 | $ | (3,909 | ) | $ | (2,008 | ) | $ | (2,585 | ) | ||||||||||||||||
Unrealized net holding gain on securities Balance at January 1 | $ | 19 | $ | – | $ | 88 | |||||||||||||||||||
Change during year | (6 | ) | 19 | (88 | ) | ||||||||||||||||||||
Balance at December 31 | $ | 13 | $ | 19 | $ | – | |||||||||||||||||||
Net derivatives gain (loss) on hedge transactions | |||||||||||||||||||||||||
Balance at January 1 | $ | 33 | $ | 39 | $ | (28 | ) | ||||||||||||||||||
Change during year | 110 | (6 | ) | 67 | |||||||||||||||||||||
Balance at December 31 | $ | 143 | $ | 33 | $ | 39 | |||||||||||||||||||
Balance at December 31 | $ | (3,924 | ) | $ | (2,015 | ) | $ | (2,636 | ) | ||||||||||||||||
Deferred Compensation and Benefit Plan Trust Deferred Compensation | |||||||||||||||||||||||||
Balance at January 1 | $ | (214 | ) | $ | (214 | ) | $ | (246 | ) | ||||||||||||||||
Net reduction of ESOP debt and other | 20 | – | 32 | ||||||||||||||||||||||
Balance at December 31 | (194 | ) | (214 | ) | (214 | ) | |||||||||||||||||||
Benefit Plan Trust (Common Stock) | 14,168 | (240 | ) | 14,168 | (240 | ) | 14,168 | (240 | ) | ||||||||||||||||
Balance at December 31 | 14,168 | $ | (434 | ) | 14,168 | $ | (454 | ) | 14,168 | $ | (454 | ) | |||||||||||||
Treasury Stock at Cost | |||||||||||||||||||||||||
Balance at January 1 | 352,243 | $ | (18,892 | ) | 278,118 | $ | (12,395 | ) | 209,990 | $ | (7,870 | ) | |||||||||||||
Purchases | 95,631 | (8,011 | ) | 85,429 | (7,036 | ) | 80,369 | (5,033 | ) | ||||||||||||||||
Issuances – mainly employee benefit plans | (9,429 | ) | 527 | (11,304 | ) | 539 | (12,241 | ) | 508 | ||||||||||||||||
Balance at December 31 | 438,445 | $ | (26,376 | ) | 352,243 | $ | (18,892 | ) | 278,118 | $ | (12,395 | ) | |||||||||||||
Total Stockholders’ Equity at December 31 | $ | 86,648 | $ | 77,088 | $ | 68,935 | |||||||||||||||||||
FS-31
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Summary of Significant Accounting Policies
Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and variable-interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent or for which the company exercises significant influence but not control over policy decisions are accounted for by the equity method. As part of that accounting, the company recognizes gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company’s proportionate share of the dollar amount of the affiliate’s equity currently in income.
performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value.
Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity and foreign currency exposures, gains and losses from derivative instruments are reported in current income. Interest rate swaps – hedging a portion of the company’s fixed-rate debt – are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the Consolidated Balance Sheet, with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are offset on the balance sheet.
Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt securities. Those investments that are part of the company’s cash management portfolio and have original maturities of three months or less are reported as “Cash equivalents.” The balance of the short-term investments is reported as “Marketable securities” and is marked-to-market, with any unrealized gains or losses included in “Other comprehensive income.”
Inventories Crude oil, petroleum products and chemicals are generally stated at cost, using a Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories generally are stated at average cost.
FS-32
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Note 1Summary of Significant Accounting Policies - Continued |
legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 24, beginning on page FS-58, relating to AROs.
Goodwill Goodwill resulting from a business combination is not subject to amortization. As required by FASB Statement No. 142,Goodwill and Other Intangible Assets, the company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.
Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
FS-33
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 1Summary of Significant Accounting Policies - Continued | |||||||||
Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency translations are currently included in income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in the currency translation adjustment in “Stockholders’ Equity.”
Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are generally recognized on the basis of the company’s net working interest (entitlement method). Excise, value-added and similar taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer are presented on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income on page FS-27. Refer to Note 14, on page FS-43, for a discussion of the accounting for buy/sell arrangements.
Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to its employees and accounts for these transactions under the provisions of FASB Statement No. 123R,Share-Based Payment(FAS 123R). For equity awards, such as stock options, total compensation cost is based on the grant date fair value and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement
Note 2
Information Relating to the Consolidated Statement of Cash Flows
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Net (increase) decrease in operating working capital was composed of the following: | |||||||||||||
Decrease (increase) in accounts and notes receivable | $ | 6,030 | $ | (3,867 | ) | $ | 17 | ||||||
Increase in inventories | (1,545 | ) | (749 | ) | (536 | ) | |||||||
Increase in prepaid expenses and other current assets | (621 | ) | (370 | ) | (31 | ) | |||||||
(Decrease) increase in accounts payable and accrued liabilities | (4,628 | ) | 4,930 | 1,246 | |||||||||
(Decrease) increase in income and other taxes payable | (909 | ) | 741 | 348 | |||||||||
Net (increase) decrease in operating working capital | $ | (1,673 | ) | $ | 685 | $ | 1,044 | ||||||
Net cash provided by operating activities includes the following cash payments for interest and income taxes: | |||||||||||||
Interest paid on debt (net of capitalized interest) | $ | – | $ | 203 | $ | 470 | |||||||
Income taxes | $ | 19,130 | $ | 12,340 | $ | 13,806 | |||||||
Net sales of marketable securities consisted of the following gross amounts: | |||||||||||||
Marketable securities sold | $ | 3,719 | $ | 2,160 | $ | 1,413 | |||||||
Marketable securities purchased | (3,236 | ) | (1,975 | ) | (1,271 | ) | |||||||
Net sales of marketable securities | $ | 483 | $ | 185 | $ | 142 | |||||||
FS-34
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Note 2Information Relating to the Consolidated Statement of Cash Flows - Continued |
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Additions to properties, plant and equipment* | $ | 18,495 | $ | 16,127 | $ | 12,800 | |||||||
Additions to investments | 1,051 | 881 | 880 | ||||||||||
Current-year dry hole expenditures | 320 | 418 | 400 | ||||||||||
Payments for other liabilities and assets, net | (200 | ) | (748 | ) | (267 | ) | |||||||
Capital expenditures | 19,666 | 16,678 | 13,813 | ||||||||||
Expensed exploration expenditures | 794 | 816 | 844 | ||||||||||
Assets acquired through capital lease obligations and other financing obligations | 9 | 196 | 35 | ||||||||||
Capital and exploratory expenditures, excluding equity affiliates | 20,469 | 17,690 | 14,692 | ||||||||||
Equity in affiliates’ expenditures | 2,306 | 2,336 | 1,919 | ||||||||||
Capital and exploratory expenditures, including equity affiliates | $ | 22,775 | $ | 20,026 | $ | 16,611 | |||||||
Note 3
Note 4
FS-35
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 4Summarized Financial Data – Chevron U.S.A. Inc. - Continued | |||||||||
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Sales and other operating revenues | $ | 195,593 | $ | 153,574 | $ | 145,774 | |||||||
Total costs and other deductions | 185,788 | 147,510 | 137,765 | ||||||||||
Net income | 7,237 | 5,203 | 5,668 | ||||||||||
At December 31 | |||||||||
2008 | 2007 | ||||||||
Current assets | $ | 32,760 | $ | 32,801 | |||||
Other assets | 31,806 | 27,400 | |||||||
Current liabilities | 14,322 | 20,050 | |||||||
Other liabilities | 14,805 | 11,447 | |||||||
Net equity | 35,439 | 28,704 | |||||||
Memo: Total debt | $ | 6,813 | $ | 4,433 |
Note 5
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Sales and other operating revenues | $ | 1,022 | $ | 667 | $ | 692 | |||||||
Total costs and other deductions | 947 | 713 | 602 | ||||||||||
Net income | 120 | (39 | ) | 119 | |||||||||
At December 31 | |||||||||
2008 | 2007 | ||||||||
Current assets | $ | 482 | $ | 335 | |||||
Other assets | 172 | 337 | |||||||
Current liabilities | 98 | 107 | |||||||
Other liabilities | 88 | 188 | |||||||
Net equity | 468 | 377 | |||||||
There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2008.
Note 6
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Sales and other operating revenues | $ | 14,329 | $ | 8,919 | $ | 7,654 | |||||||
Costs and other deductions | 5,621 | 3,387 | 2,967 | ||||||||||
Net income | 6,134 | 3,952 | 3,315 | ||||||||||
At December 31 | |||||||||
2008 | 2007 | �� | |||||||
Current assets | $ | 2,740 | $ | 2,784 | |||||
Other assets | 12,240 | 11,446 | |||||||
Current liabilities | 1,867 | 1,534 | |||||||
Other liabilities | 4,759 | 4,927 | |||||||
Net equity | 8,354 | 7,769 | |||||||
Note 7
FS-36
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Note 7Financial and Derivative Instruments - Continued |
are reported as either “Sales and other operating revenues” or “Purchased crude oil and products,” whereas trading gains and losses are reported as “Other income.”
Foreign Currency The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments, forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.
Interest Rates The company enters into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps related to a portion of the company’s fixed-rate debt are accounted for as fair value hedges.
Fair Value Fair values are derived from quoted market prices, other independent third-party quotes or, if not available, the present value of the expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end.
Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. This diversified investment policy limits the company’s exposure both to credit risk and to concentrations of credit risk. Similar standards of diversity and creditworthiness are applied to the company’s counterparties in derivative instruments.
Fair Value Measurements
FS-37
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 8Fair Value Measurements - Continued | |||||||||
company uses to value an asset or a liability. The three levels of the fair-value hierarchy are described as follows:
The fair-value hierarchy for assets and liabilities measured at fair value at December 31, 2008, is as follows:
Assets and Liabilities Measured at
Fair Value on a Recurring Basis
Prices in Active | ||||||||||||||||
Markets for | Other | |||||||||||||||
Identical | Observable | Unobservable | ||||||||||||||
At December 31 | Assets/Liabilities | Inputs | Inputs | |||||||||||||
2008 | (Level 1) | (Level 2) | (Level 3) | |||||||||||||
Marketable Securities | $ | 213 | $ | 213 | $ | – | $ | – | ||||||||
Derivatives | 805 | 529 | 276 | – | ||||||||||||
Total Assets at Fair Value | $ | 1,018 | $ | 742 | $ | 276 | $ | – | ||||||||
Derivatives | $ | 516 | $ | 98 | $ | 418 | $ | – | ||||||||
Total Liabilities at Fair Value | $ | 516 | $ | 98 | $ | 418 | $ | – | ||||||||
Marketable securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets and liabilities.
Operating Segments and Geographic Data
FS-38
Table of Contents
Note 9Operating Segments and Geographic Data - Continued |
projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations. Company officers who are members of the Executive Committee also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM.
Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” After-tax segment income by major operating area is presented in the following table:
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Income by Major Operating Area | |||||||||||||
Upstream | |||||||||||||
United States | $ | 7,126 | $ | 4,532 | $ | 4,270 | |||||||
International | 14,584 | 10,284 | 8,872 | ||||||||||
Total Upstream | 21,710 | 14,816 | 13,142 | ||||||||||
Downstream | |||||||||||||
United States | 1,369 | 966 | 1,938 | ||||||||||
International | 2,060 | 2,536 | 2,035 | ||||||||||
Total Downstream | 3,429 | 3,502 | 3,973 | ||||||||||
Chemicals | |||||||||||||
United States | 22 | 253 | 430 | ||||||||||
International | 160 | 143 | 109 | ||||||||||
Total Chemicals | 182 | 396 | 539 | ||||||||||
Total Segment Income | 25,321 | 18,714 | 17,654 | ||||||||||
All Other | |||||||||||||
Interest expense | – | (107 | ) | (312 | ) | ||||||||
Interest income | 192 | 385 | 380 | ||||||||||
Other | (1,582 | ) | (304 | ) | (584 | ) | |||||||
Net Income | $ | 23,931 | $ | 18,688 | $ | 17,138 | |||||||
Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 2008 and 2007 are as follows:
At December 31 | |||||||||
2008 | 2007 | ||||||||
Upstream | |||||||||
United States | $ | 26,071 | $ | 23,535 | |||||
International | 72,530 | 61,049 | |||||||
Goodwill | 4,619 | 4,637 | |||||||
Total Upstream | 103,220 | 89,221 | |||||||
Downstream | |||||||||
United States | 15,869 | 16,790 | |||||||
International | 23,572 | 26,075 | |||||||
Total Downstream | 39,441 | 42,865 | |||||||
Chemicals | |||||||||
United States | 2,535 | 2,484 | |||||||
International | 1,086 | 870 | |||||||
Total Chemicals | 3,621 | 3,354 | |||||||
Total Segment Assets | 146,282 | 135,440 | |||||||
All Other* | |||||||||
United States | 8,984 | 6,847 | |||||||
International | 5,899 | 6,499 | |||||||
Total All Other | 14,883 | 13,346 | |||||||
Total Assets – United States | 53,459 | 49,656 | |||||||
Total Assets – International | 103,087 | 94,493 | |||||||
Goodwill | 4,619 | 4,637 | |||||||
Total Assets | $ | 161,165 | $ | 148,786 | |||||
* | “All Other” assets consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, information systems, mining operations, power generation businesses, technology companies, and assets of the corporate administrative functions. |
Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2008, 2007 and 2006 are presented in the table on the following page. Products are transferred between operating segments at internal product values that approximate market prices.
FS-39
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 9Operating Segments and Geographic Data - Continued | |||||||||
Other than the United States, no single country accounted for 10 percent or more of the company’s total sales and other operating revenues in 2008.
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Upstream | |||||||||||||
United States | $ | 23,503 | $ | 18,736 | $ | 18,061 | |||||||
Intersegment | 15,142 | 11,625 | 10,069 | ||||||||||
Total United States | 38,645 | 30,361 | 28,130 | ||||||||||
International | 19,469 | 15,213 | 14,560 | ||||||||||
Intersegment | 24,204 | 19,647 | 17,139 | ||||||||||
Total International | 43,673 | 34,860 | 31,699 | ||||||||||
Total Upstream | 82,318 | 65,221 | 59,829 | ||||||||||
Downstream | |||||||||||||
United States | 87,515 | 70,535 | 69,367 | ||||||||||
Excise and similar taxes | 4,746 | 4,990 | 4,829 | ||||||||||
Intersegment | 447 | 491 | 533 | ||||||||||
Total United States | 92,708 | 76,016 | 74,729 | ||||||||||
International | 122,064 | 97,178 | 91,325 | ||||||||||
Excise and similar taxes | 5,044 | 5,042 | 4,657 | ||||||||||
Intersegment | 122 | 38 | 37 | ||||||||||
Total International | 127,230 | 102,258 | 96,019 | ||||||||||
Total Downstream | 219,938 | 178,274 | 170,748 | ||||||||||
Chemicals | |||||||||||||
United States | 305 | 351 | 372 | ||||||||||
Excise and similar taxes | 2 | 2 | 2 | ||||||||||
Intersegment | 266 | 235 | 243 | ||||||||||
Total United States | 573 | 588 | 617 | ||||||||||
International | 1,388 | 1,143 | 959 | ||||||||||
Excise and similar taxes | 55 | 86 | 63 | ||||||||||
Intersegment | 154 | 142 | 160 | ||||||||||
Total International | 1,597 | 1,371 | 1,182 | ||||||||||
Total Chemicals | 2,170 | 1,959 | 1,799 | ||||||||||
All Other | |||||||||||||
United States | 815 | 757 | 653 | ||||||||||
Intersegment | 917 | 760 | 584 | ||||||||||
Total United States | 1,732 | 1,517 | 1,237 | ||||||||||
International | 52 | 58 | 44 | ||||||||||
Intersegment | 33 | 31 | 23 | ||||||||||
Total International | 85 | 89 | 67 | ||||||||||
Total All Other | 1,817 | 1,606 | 1,304 | ||||||||||
Segment Sales and Other Operating Revenues | |||||||||||||
United States | 133,658 | 108,482 | 104,713 | ||||||||||
International | 172,585 | 138,578 | 128,967 | ||||||||||
Total Segment Sales and Other Operating Revenues | 306,243 | 247,060 | 233,680 | ||||||||||
Elimination of intersegment sales | (41,285 | ) | (32,969 | ) | (28,788 | ) | |||||||
Total Sales and Other Operating Revenues* | $ | 264,958 | $ | 214,091 | $ | 204,892 | |||||||
* | Includes buy/sell contracts of $6,725 in 2006. Substantially all of the amounts relate to the downstream segment. Refer to Note 14, on page FS-43, for a discussion of the company’s accounting for buy/sell contracts. |
Segment Income Taxes Segment income tax expense for the years 2008, 2007 and 2006 are as follows:
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Upstream | |||||||||||||
United States | $ | 3,693 | $ | 2,541 | $ | 2,668 | |||||||
International | 15,132 | 11,307 | 10,987 | ||||||||||
Total Upstream | 18,825 | 13,848 | 13,655 | ||||||||||
Downstream | |||||||||||||
United States | 815 | 520 | 1,162 | ||||||||||
International | 813 | 400 | 586 | ||||||||||
Total Downstream | 1,628 | 920 | 1,748 | ||||||||||
Chemicals | |||||||||||||
United States | (22 | ) | 6 | 213 | |||||||||
International | 47 | 36 | 30 | ||||||||||
Total Chemicals | 25 | 42 | 243 | ||||||||||
All Other | (1,452 | ) | (1,331 | ) | (808 | ) | |||||||
Total Income Tax Expense | $ | 19,026 | $ | 13,479 | $ | 14,838 | |||||||
Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 12, beginning on page FS-41. Information related to properties, plant and equipment by segment is contained in Note 13, on page FS-43.
Lease Commitments
At December 31 | |||||||||
2008 | 2007 | ||||||||
Upstream | $ | 491 | $ | 482 | |||||
Downstream | $ | 399 | $ | 551 | |||||
Chemical and all other | 171 | 171 | |||||||
Total | 1,061 | 1,204 | |||||||
Less: Accumulated amortization | 522 | 628 | |||||||
Net capitalized leased assets | $ | 539 | $ | 576 | |||||
Rental expenses incurred for operating leases during 2008, 2007 and 2006 were as follows:
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Minimum rentals | $ | 2,984 | $ | 2,419 | $ | 2,326 | |||||||
Contingent rentals | 6 | 6 | 6 | ||||||||||
Total | 2,990 | 2,425 | 2,332 | ||||||||||
Less: Sublease rental income | 41 | 30 | 33 | ||||||||||
Net rental expense | $ | 2,949 | $ | 2,395 | $ | 2,299 | |||||||
FS-40
Table of Contents
Note 10Lease Commitments - Continued |
At December 31 | |||||||||
Operating | Capital | ||||||||
Leases | Leases | ||||||||
Year: 2009 | $ | 503 | $ | 97 | |||||
2010 | 463 | 77 | |||||||
2011 | 372 | 77 | |||||||
2012 | 315 | 84 | |||||||
2013 | 288 | 59 | |||||||
Thereafter | 947 | 154 | |||||||
Total | $ | 2,888 | $ | 548 | |||||
Less: Amounts representing interest and executory costs | (110 | ) | |||||||
Net present values | 438 | ||||||||
Less: Capital lease obligations included in short-term debt | (97 | ) | |||||||
Long-term capital lease obligations | $ | 341 | |||||||
Note 11
Restructuring and Reorganization Costs
Amounts before tax | 2008 | 2007 | |||||||
Balance at January 1 | $ | 85 | $ | – | |||||
Accruals/adjustments | (11 | ) | 85 | ||||||
Payments | (52 | ) | – | ||||||
Balance at December 31 | $ | 22 | $ | 85 | |||||
Note 12
Investments and Advances
Investments and Advances | Equity in Earnings | ||||||||||||||||||||
At December 31 | Year ended December 31 | ||||||||||||||||||||
2008 | 2007 | 2008 | 2007 | 2006 | |||||||||||||||||
Upstream | |||||||||||||||||||||
Tengizchevroil | $ | 6,290 | $ | 6,321 | $ | 3,220 | $ | 2,135 | $ | 1,817 | |||||||||||
Petropiar/Hamaca | 1,130 | 1,168 | 317 | 327 | 319 | ||||||||||||||||
Petroboscan | 816 | 762 | 244 | 185 | 31 | ||||||||||||||||
Angola LNG Limited | 1,191 | 574 | (8 | ) | 21 | – | |||||||||||||||
Other | 725 | 765 | 206 | 204 | 123 | ||||||||||||||||
Total Upstream | 10,152 | 9,590 | 3,979 | 2,872 | 2,290 | ||||||||||||||||
Downstream | |||||||||||||||||||||
GS Caltex Corporation | 2,601 | 2,276 | 444 | 217 | 316 | ||||||||||||||||
Caspian Pipeline Consortium | 749 | 951 | 103 | 102 | 117 | ||||||||||||||||
Star Petroleum Refining Company Ltd. | 877 | 944 | 22 | 157 | 116 | ||||||||||||||||
Escravos Gas-to-Liquids | – | 628 | 86 | 103 | 146 | ||||||||||||||||
Caltex Australia Ltd. | 723 | 580 | 250 | 129 | 186 | ||||||||||||||||
Colonial Pipeline Company | 536 | 546 | 32 | 39 | 34 | ||||||||||||||||
Other | 1,664 | 1,501 | 268 | 215 | 212 | ||||||||||||||||
Total Downstream | 7,150 | 7,426 | 1,205 | 962 | 1,127 | ||||||||||||||||
Chemicals | |||||||||||||||||||||
Chevron Phillips Chemical Company LLC | 2,037 | 2,024 | 158 | 380 | 697 | ||||||||||||||||
Other | 25 | 24 | 4 | 6 | 5 | ||||||||||||||||
Total Chemicals | 2,062 | 2,048 | 162 | 386 | 702 | ||||||||||||||||
All Other | |||||||||||||||||||||
Other | 567 | 449 | 20 | (76 | ) | 136 | |||||||||||||||
Total equity method | $ | 19,931 | $ | 19,513 | $ | 5,366 | $ | 4,144 | $ | 4,255 | |||||||||||
Other at or below cost | 989 | 964 | |||||||||||||||||||
Total investments and advances | $ | 20,920 | $ | 20,477 | |||||||||||||||||
Total United States | $ | 4,002 | $ | 3,889 | $ | 307 | $ | 478 | $ | 955 | |||||||||||
Total International | $ | 16,918 | $ | 16,588 | $ | 5,059 | $ | 3,666 | $ | 3,300 | |||||||||||
40-year period. At December 31, 2008, the company’s carrying value of its investment in TCO was about $210 higher than the amount of underlying equity in TCO net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying equity for that portion of TCO’s assets.
FS-41
Table of Contents
Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 12Investments and Advances - Continued | |||||||||
Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company formed in 2008 to operate the Hamaca heavy oil production and upgrading project. The project, located in Venezuela’s Orinoco Belt, has a 25-year contract term. Prior to the formation of Petropiar, Chevron had a 30 percent interest in the Hamaca project. At December 31, 2008, the company’s carrying value of its investment in Petropiar was approximately $250 less than the amount of underlying equity in Petropiar net assets. The difference represents the excess of Chevron’s underlying equity in Petropiar’s net assets over the net book value of the assets contributed to the venture.
Petroboscan Chevron has a 39 percent interest in Petroboscan, a joint stock company formed in 2006 to operate the Boscan Field in Venezuela until 2026. Chevron previously operated the field under an operating service agreement. At December 31, 2008, the company’s carrying value of its investment in Petroboscan was approximately $290 higher than the amount of underlying equity in Petroboscan net assets. The difference reflects the excess of the net book value of the assets contributed by Chevron over its underlying equity in Petroboscan’s net assets.
Angola LNG Ltd. Chevron has a 36 percent interest in Angola LNG Ltd., which will process and liquefy natural gas produced in Angola for delivery to international markets.
GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Holdings. The joint venture imports, refines and markets petroleum products and petrochemicals, predominantly in South Korea.
Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, which provides the critical export route for crude oil from both TCO and Karachaganak.
Star Petroleum Refining Company Ltd. Chevron has a 64 percent equity ownership interest in Star Petroleum Refining Company Ltd. (SPRC), which owns the Star Refinery in Thailand. The Petroleum Authority of Thailand owns the remaining 36 percent of SPRC.
Escravos Gas-to-Liquids Chevron Nigeria Limited (CNL) has a 75 percent interest in Escravos Gas-to-Liquids (EGTL) with the other 25 percent of the joint venture owned by Nigeria National Petroleum Company. Until December 1, 2008, Sasol Ltd. provided 50 percent of CNL’s funding require-
Caltex Australia Ltd. Chevron has a 50 percent equity ownership interest in Caltex Australia Ltd. (CAL). The remaining 50 percent of CAL is publicly owned. At December 31, 2008, the fair value of Chevron’s share of CAL common stock was approximately $670. The decline in value below the company’s carrying value of $723 million at the end of 2008 was deemed temporary.
Colonial Pipeline Company Chevron owns an approximate 23 percent equity interest in the Colonial Pipeline Company. The Colonial Pipeline system runs from Texas to New Jersey and transports petroleum products in a 13-state market. At December 31, 2008, the company’s carrying value of its investment in Colonial Pipeline was approximately $560 higher than the amount of underlying equity in Colonial Pipeline net assets. This difference primarily relates to purchase price adjustments from the acquisition of Unocal Corporation.
Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC (CPChem), with the other half owned by ConocoPhillips Corporation.
Dynegy Inc. In 2007, Chevron sold its 19 percent common stock investment in Dynegy Inc., for approximately $940, resulting in a gain of $680.
Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $15,390, $11,555 and $9,582 with affiliated companies for 2008, 2007 and 2006, respectively. “Purchased crude oil and products” includes $6,850, $5,464 and $4,222 with affiliated companies for 2008, 2007 and 2006, respectively.
FS-42
Table of Contents
Note 12Investments and Advances - Continued |
Affiliates | Chevron Share | ||||||||||||||||||||||||
Year ended December 31 | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | |||||||||||||||||||
Total revenues | $ | 112,707 | $ | 94,864 | $ | 73,746 | $ | 54,055 | $ | 46,579 | $ | 35,695 | |||||||||||||
Income before income tax expense | 17,500 | 12,510 | 10,973 | 7,532 | 5,836 | 5,295 | |||||||||||||||||||
Net income | 12,705 | 9,743 | 7,905 | 5,524 | 4,550 | 4,072 | |||||||||||||||||||
At December 31 | |||||||||||||||||||||||||
Current assets | $ | 25,194 | $ | 26,360 | $ | 19,769 | $ | 10,804 | $ | 11,914 | $ | 8,944 | |||||||||||||
Noncurrent assets | 51,878 | 48,440 | 49,896 | 20,129 | 19,045 | 18,575 | |||||||||||||||||||
Current liabilities | 17,727 | 19,033 | 15,254 | 7,474 | 9,009 | 6,818 | |||||||||||||||||||
Noncurrent liabilities | 21,049 | 22,757 | 24,059 | 4,533 | 3,745 | 3,902 | |||||||||||||||||||
Net equity | $ | 38,296 | $ | 33,010 | $ | 30,352 | $ | 18,926 | $ | 18,205 | $ | 16,799 | |||||||||||||
Note 13
Properties, Plant and Equipment
At December 31 | Year ended December 31 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Investment at Cost | Net Investment | Additions at Cost1 | Depreciation Expense2 | ||||||||||||||||||||||||||||||||||||||||||||||||
2008 | 2007 | 2006 | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | ||||||||||||||||||||||||||||||||||||||||
Upstream | |||||||||||||||||||||||||||||||||||||||||||||||||||
United States | $ | 54,156 | $ | 50,991 | $ | 46,191 | $ | 22,294 | $ | 19,850 | $ | 16,706 | $ | 5,374 | $ | 5,725 | $ | 3,739 | $ | 2,683 | $ | 2,700 | $ | 2,374 | |||||||||||||||||||||||||||
International | 84,282 | 71,408 | 61,281 | 51,140 | 43,431 | 37,730 | 13,177 | 10,512 | 7,290 | 5,441 | 4,605 | 3,888 | |||||||||||||||||||||||||||||||||||||||
Total Upstream | 138,438 | 122,399 | 107,472 | 73,434 | 63,281 | 54,436 | 18,551 | 16,237 | 11,029 | 8,124 | 7,305 | 6,262 | |||||||||||||||||||||||||||||||||||||||
Downstream | |||||||||||||||||||||||||||||||||||||||||||||||||||
United States | 17,394 | 15,807 | 14,553 | 8,977 | 7,685 | 6,741 | 2,032 | 1,514 | 1,109 | 629 | 509 | 474 | |||||||||||||||||||||||||||||||||||||||
International | 11,587 | 10,471 | 11,036 | 6,001 | 4,690 | 5,233 | 2,285 | 519 | 532 | 469 | 633 | 551 | |||||||||||||||||||||||||||||||||||||||
Total Downstream | 28,981 | 26,278 | 25,589 | 14,978 | 12,375 | 11,974 | 4,317 | 2,033 | 1,641 | 1,098 | 1,142 | 1,025 | |||||||||||||||||||||||||||||||||||||||
Chemicals | |||||||||||||||||||||||||||||||||||||||||||||||||||
United States | 725 | 678 | 645 | 338 | 308 | 289 | 50 | 40 | 25 | 19 | 19 | 19 | |||||||||||||||||||||||||||||||||||||||
International | 828 | 815 | 771 | 496 | 453 | 431 | 72 | 53 | 54 | 33 | 26 | 24 | |||||||||||||||||||||||||||||||||||||||
Total Chemicals | 1,553 | 1,493 | 1,416 | 834 | 761 | 720 | 122 | 93 | 79 | 52 | 45 | 43 | |||||||||||||||||||||||||||||||||||||||
All Other3 | |||||||||||||||||||||||||||||||||||||||||||||||||||
United States | 4,310 | 3,873 | 3,243 | 2,523 | 2,179 | 1,709 | 598 | 680 | 270 | 250 | 215 | 171 | |||||||||||||||||||||||||||||||||||||||
International | 17 | 41 | 27 | 11 | 14 | 19 | 5 | 5 | 8 | 4 | 1 | 5 | |||||||||||||||||||||||||||||||||||||||
Total All Other | 4,327 | 3,914 | 3,270 | 2,534 | 2,193 | 1,728 | 603 | 685 | 278 | 254 | 216 | 176 | |||||||||||||||||||||||||||||||||||||||
Total United States | 76,585 | 71,349 | 64,632 | 34,132 | 30,022 | 25,445 | 8,054 | 7,959 | 5,143 | 3,581 | 3,443 | 3,038 | |||||||||||||||||||||||||||||||||||||||
Total International | 96,714 | 82,735 | 73,115 | 57,648 | 48,588 | 43,413 | 15,539 | 11,089 | 7,884 | 5,947 | 5,265 | 4,468 | |||||||||||||||||||||||||||||||||||||||
Total | $ | 173,299 | $ | 154,084 | $ | 137,747 | $ | 91,780 | $ | 78,610 | $ | 68,858 | $ | 23,593 | $ | 19,048 | $ | 13,027 | $ | 9,528 | $ | 8,708 | $ | 7,506 | |||||||||||||||||||||||||||
Note 14
Accounting for Buy/Sell Contracts
FS-43
Table of Contents
Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 15Litigation | |||||||||
Note 15
Litigation
RFG Patent Fourteen purported class actions were brought by consumers who purchased reformulated gasoline (RFG) from January 1995 through August 2005, alleging that Unocal misled the California Air Resources Board into adopting standards for composition of RFG that overlapped with Unocal’s undisclosed and pending patents. The parties agreed to a settlement that calls for, among other things, Unocal to pay $48 and for the establishment of acy presfund to administer payout of the award. The court approved the final settlement in November 2008.
Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations, and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned
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Note 15Litigation - Continued |
Note 16
Taxes
Income Taxes
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Taxes on income | |||||||||||||
U.S. Federal | |||||||||||||
Current | $ | 2,879 | $ | 1,446 | $ | 2,828 | |||||||
Deferred | 274 | 225 | 200 | ||||||||||
State and local | 669 | 338 | 581 | ||||||||||
Total United States | 3,822 | 2,009 | 3,609 | ||||||||||
International | |||||||||||||
Current | 15,021 | 11,416 | 11,030 | ||||||||||
Deferred | 183 | 54 | 199 | ||||||||||
Total International | 15,204 | 11,470 | 11,229 | ||||||||||
Total taxes on income | $ | 19,026 | $ | 13,479 | $ | 14,838 | |||||||
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
U.S. statutory federal income tax rate | 35.0 | % | 35.0 | % | 35.0 | % | |||||||
Effect of income taxes from international operations at rates different from the U.S. statutory rate | 10.2 | 8.3 | 10.3 | ||||||||||
State and local taxes on income, net of U.S. federal income tax benefit | 1.0 | 0.8 | 1.0 | ||||||||||
Prior-year tax adjustments | (0.1 | ) | 0.3 | 0.9 | |||||||||
Tax credits | (0.5 | ) | (0.4 | ) | (0.4 | ) | |||||||
Effects of enacted changes in tax laws | (0.6 | ) | (0.3 | ) | 0.3 | ||||||||
Other | (0.7 | ) | (1.8 | ) | (0.7 | ) | |||||||
Effective tax rate | 44.3 | % | 41.9 | % | 46.4 | % | |||||||
At December 31 | ||||||||||||
2008 | 2007 | |||||||||||
Deferred tax liabilities | ||||||||||||
Properties, plant and equipment | $ | 18,271 | $ | 17,310 | ||||||||
Investments and other | 2,225 | 1,837 | ||||||||||
Total deferred tax liabilities | 20,496 | 19,147 | ||||||||||
Deferred tax assets | ||||||||||||
Abandonment/environmental reserves | (4,338 | ) | (3,587 | ) | ||||||||
Employee benefits | (3,488 | ) | (2,148 | ) | ||||||||
Tax loss carryforwards | (1,139 | ) | (1,603 | ) | ||||||||
Deferred credits | (3,933 | ) | (1,689 | ) | ||||||||
Foreign tax credits | (4,784 | ) | (3,138 | ) | ||||||||
Inventory | (260 | ) | (608 | ) | ||||||||
Other accrued liabilities | (445 | ) | (477 | ) | ||||||||
Miscellaneous | (1,732 | ) | (1,528 | ) | ||||||||
Total deferred tax assets | (20,119 | ) | (14,778 | ) | ||||||||
Deferred tax assets valuation allowance | 7,535 | 5,949 | ||||||||||
Total deferred taxes, net | $ | 7,912 | $ | 10,318 | ||||||||
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 16Taxes - Continued | |||||||||
2009 through 2032. Foreign tax credit carryforwards of $4,784 will expire between 2009 and 2018.
At December 31 | ||||||||||||
2008 | 2007 | |||||||||||
Prepaid expenses and other current assets | $ | (1,130 | ) | $ | (1,234 | ) | ||||||
Deferred charges and other assets | (2,686 | ) | (812 | ) | ||||||||
Federal and other taxes on income | 189 | 194 | ||||||||||
Noncurrent deferred income taxes | 11,539 | 12,170 | ||||||||||
Total deferred income taxes, net | $ | 7,912 | $ | 10,318 | ||||||||
2008 | 2007 | |||||||||||
Balance at January 1 | $ | 2,199 | $ | 2,296 | ||||||||
Foreign currency effects | (1 | ) | 19 | |||||||||
Additions based on tax positions taken in current year | 522 | 418 | ||||||||||
Reductions based on tax positions taken in current year | (17 | ) | – | |||||||||
Additions/reductions resulting from current year asset acquisitions/sales | 175 | – | ||||||||||
Additions for tax positions taken in prior years | 337 | 120 | ||||||||||
Reductions for tax positions taken in prior years | (246 | ) | (225 | ) | ||||||||
Settlements with taxing authorities in current year | (215 | ) | (255 | ) | ||||||||
Reductions as a result of a lapse of the applicable statute of limitations | (58 | ) | – | |||||||||
Reductions due to tax positions previously expected to be taken but subsequently not taken on prior year tax returns | – | (174 | ) | |||||||||
Balance at December 31 | $ | 2,696 | $ | 2,199 | ||||||||
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Note 16Taxes - Continued |
Taxes Other Than on Income
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
United States | |||||||||||||
Excise and similar taxes on products and merchandise | $ | 4,748 | $ | 4,992 | $ | 4,831 | |||||||
Import duties and other levies | 1 | 12 | 32 | ||||||||||
Property and other miscellaneous taxes | 588 | 491 | 475 | ||||||||||
Payroll taxes | 204 | 185 | 155 | ||||||||||
Taxes on production | 431 | 288 | 360 | ||||||||||
Total United States | 5,972 | 5,968 | 5,853 | ||||||||||
International | |||||||||||||
Excise and similar taxes on products and merchandise | 5,098 | 5,129 | 4,720 | ||||||||||
Import duties and other levies | 8,368 | 10,404 | 9,618 | ||||||||||
Property and other miscellaneous taxes | 1,557 | 528 | 491 | ||||||||||
Payroll taxes | 106 | 89 | 75 | ||||||||||
Taxes on production | 202 | 148 | 126 | ||||||||||
Total International | 15,331 | 16,298 | 15,030 | ||||||||||
Total taxes other than on income | $ | 21,303 | $ | 22,266 | $ | 20,883 | |||||||
Note 17
Short-Term Debt
At December 31 | |||||||||
2008 | 2007 | ||||||||
Commercial paper* | $ | 5,742 | $ | 3,030 | |||||
Notes payable to banks and others with originating terms of one year or less | 149 | 219 | |||||||
Current maturities of long-term debt | 429 | 850 | |||||||
Current maturities of long-term capital leases | 78 | 73 | |||||||
Redeemable long-term obligations | |||||||||
Long-term debt | 1,351 | 1,351 | |||||||
Capital leases | 19 | 21 | |||||||
Subtotal | 7,768 | 5,544 | |||||||
Reclassified to long-term debt | (4,950 | ) | (4,382 | ) | |||||
Total short-term debt | $ | 2,818 | $ | 1,162 | |||||
Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders within one year following the balance sheet date.
The company periodically enters into interest rate swaps on a portion of its short-term debt. See Note 7, beginning on page FS-36, for information concerning the company’s debt-related derivative activities.
At December 31, 2008, the company had $4,950 of committed credit facilities with banks worldwide, which permit
Note 18
Long-Term Debt
At December 31 | |||||||||
2008 | 2007 | ||||||||
3.375% notes due 2008 | $ | – | $ | 749 | |||||
5.5% notes due 2009 | 400 | 405 | |||||||
7.327% amortizing notes due 20141 | 194 | 213 | |||||||
8.625% debentures due 2032 | 147 | 161 | |||||||
8.625% debentures due 2031 | 108 | 108 | |||||||
7.5% debentures due 2043 | 85 | 85 | |||||||
8% debentures due 2032 | 74 | 81 | |||||||
9.75% debentures due 2020 | 56 | 57 | |||||||
8.875% debentures due 2021 | 40 | 46 | |||||||
8.625% debentures due 2010 | 30 | 30 | |||||||
3.85% notes due 2008 | – | 30 | |||||||
Medium-term notes, maturing from 2021 to 2038 (6.2%)2 | 38 | 64 | |||||||
Fixed interest rate notes, maturing 2011 (9.378%)2 | 21 | 27 | |||||||
Other foreign currency obligations (0.5%)2 | 13 | 17 | |||||||
Other long-term debt (9.1%)2 | 15 | 59 | |||||||
Total including debt due within one year | 1,221 | 2,132 | |||||||
Debt due within one year | (429 | ) | (850 | ) | |||||
Reclassified from short-term debt | 4,950 | 4,382 | |||||||
Total long-term debt | $ | 5,742 | $ | 5,664 | |||||
Long-term debt of $1,221 matures as follows: 2009 – $429; 2010 – $64; 2011 – $47; 2012 – $33; 2013 – $41; and after 2013 – $607.
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 19New Accounting Standards | |||||||||
Note 19
New Accounting Standards
FASB Staff Position FAS 141(R)-a Accounting for Assets Acquired and Liabilities Assumed in a Business Combination (FSP FAS 141(R)-a) In February 2009, the FASB approved for issuance FSP FAS 141(R)-a, which became effective for business combinations having an acquisition date on or after January 1, 2009. This standard requires an asset or liability arising from a contingency in a business combination to be recognized at fair value if fair value can be reasonably determined. If it cannot be reasonably determined then the asset or liability will need to be recognized in accordance with FASB Statement No. 5,Accounting for Contingencies, and FASB Interpretation No. 14,Reasonable Estimation of the Amount of the Loss.
FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS 160)The FASB issued FAS 160 in December 2007, which became effective for the company January 1, 2009, with retroactive adoption of the Standard’s presentation and disclosure requirements for existing minority interests. This standard requires ownership interests in subsidiaries held by parties other than the parent to be presented within the equity section of the Consolidated Balance Sheet but separate from the parent’s equity. It also requires the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the Consolidated Statement of Income. Certain changes in a parent’s ownership interest are to be accounted for as equity transactions and when a subsidiary is deconsolidated, any noncontrolling equity investment in the former subsidiary is to be initially measured at fair value. Implementation of FAS 160 will not significantly change the presentation of the company’s Consolidated Statement of Income or Consolidated Balance Sheet.
FASB Staff Position FAS 132(R)-1, Employer’s Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1)In December 2008, the FASB issued FSP FAS 132(R)-1, which becomes effective with the company’s reporting at December 31, 2009. This standard amends and expands the disclosure requirements on the plan assets of defined benefit pension and other postretirement plans to provide users of financial statements with an understanding of: how investment allocation decisions are made; the major categories of plan assets; the inputs and valuation techniques used to measure the fair value of plan assets; the effect of fair-value measurements using significant unobservable inputs on changes in plan assets for the period; and significant concentrations of risk within plan assets. The company does not prefund its other postretirement plan obligations, and the effect on the company’s disclosures for its pension plan assets as a result of the adoption of FSP FAS 132(R)-1 will depend on the company’s plan assets at that time.
Note 20
Accounting for Suspended Exploratory Wells
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Note 20Accounting for Suspended Exploratory Wells - Continued | |||||||||
2008 | 2007 | 2006 | |||||||||||
Beginning balance at January 1 | $ | 1,660 | $ | 1,239 | $ | 1,109 | |||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 643 | 486 | 446 | ||||||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | (49 | ) | (23 | ) | (171 | ) | |||||||
Capitalized exploratory well costs charged to expense | (136 | ) | (42 | ) | (121 | ) | |||||||
Other reductions* | – | – | (24 | ) | |||||||||
Ending balance at December 31 | $ | 2,118 | $ | 1,660 | $ | 1,239 | |||||||
The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.
At December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Exploratory well costs capitalized for a period of one year or less | $ | 559 | $ | 449 | $ | 332 | |||||||
Exploratory well costs capitalized for a period greater than one year | 1,559 | 1,211 | 907 | ||||||||||
Balance at December 31 | $ | 2,118 | $ | 1,660 | $ | 1,239 | |||||||
Number of projects with exploratory well costs that have been capitalized for a period greater than one year* | 50 | 54 | 44 | ||||||||||
Of the $1,559 of exploratory well costs capitalized for more than one year at December 31, 2008, $874 (27 projects) is related to projects that had drilling activities under way or firmly planned for the near future. An additional $279 (four projects) is related to projects that had drilling activity during 2008. The $406 balance is related to 19 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.
Number | ||||||||
Aging based on drilling completion date of individual wells: | Amount | of wells | ||||||
1992 | $ | 7 | 3 | |||||
1994–1997 | 31 | 4 | ||||||
1998–2002 | 176 | 34 | ||||||
2003–2007 | 1,345 | 154 | ||||||
Total | $ | 1,559 | 195 | |||||
Aging based on drilling completion date of last | Number | |||||||
suspended well in project: | Amount | of projects | ||||||
1992 | $ | 7 | 1 | |||||
1999 | 8 | 1 | ||||||
2003 | 69 | 3 | ||||||
2004–2008 | 1,475 | 45 | ||||||
Total | $ | 1,559 | 50 | |||||
Note 21
Stock Options and Other Share-Based Compensation
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 21Stock Options and Other Share-Based Compensation - Continued | |||||||||
Chevron Long-Term Incentive Plan (LTIP)Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance units and nonstock grants. From April 2004 through January 2014, no more than 160 million shares may be issued under the LTIP, and no more than 64 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient.
Texaco Stock Incentive Plan (Texaco SIP) On the closing of the acquisition of Texaco in October 2001, outstanding options granted under the Texaco SIP were converted to Chevron options. These options, which have 10-year contractual lives extending into 2011, retained a provision for being restored. This provision enables a participant who exercises a stock option to receive new options equal to the number of shares exchanged or who has shares withheld to satisfy tax withholding obligations to receive new options equal to the number of shares exchanged or withheld. The restored options are fully exercisable six months after the date of grant, and the exercise price is the market value of the common stock on the day the restored option is granted. Beginning in 2007, restored options were granted under the LTIP. No further awards may be granted under the former Texaco plans.
Unocal Share-Based Plans (Unocal Plans) When Chevron acquired Unocal in August 2005, outstanding stock options and stock appreciation rights granted under various Unocal Plans were exchanged for fully vested Chevron options and appreciation rights. These awards retained the same provisions as the original Unocal Plans. If not exercised, these awards will expire between early 2009 and early 2015.
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Stock Options | |||||||||||||
Expected term in years1 | 6.1 | 6.3 | 6.4 | ||||||||||
Volatility2 | 22.0 | % | 22.0 | % | 23.7 | % | |||||||
Risk-free interest rate based on zero coupon U.S. treasury note | 3.0 | % | 4.5 | % | 4.7 | % | |||||||
Dividend yield | 2.7 | % | 3.2 | % | 3.1 | % | |||||||
Weighted-average fair value per option granted | $ | 15.97 | $ | 15.27 | $ | 12.74 | |||||||
Restored Options | |||||||||||||
Expected term in years1 | 1.2 | 1.6 | 2.2 | ||||||||||
Volatility2 | 23.1 | % | 21.2 | % | 19.6 | % | |||||||
Risk-free interest rate based on zero coupon U.S. treasury note | 1.9 | % | 4.5 | % | 4.8 | % | |||||||
Dividend yield | 2.7 | % | 3.2 | % | 3.3 | % | |||||||
Weighted-average fair value per option granted | $ | 10.01 | $ | 8.61 | $ | 7.72 | |||||||
1 | Expected term is based on historical exercise and post-vesting cancellation data. | |
2 | Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term. |
A summary of option activity during 2008 is presented below:
Weighted- | ||||||||||||||||
Weighted- | Average | |||||||||||||||
Average | Remaining | Aggregate | ||||||||||||||
Shares | Exercise | Contractual | Intrinsic | |||||||||||||
(Thousands) | Price | Term | Value | |||||||||||||
Outstanding at January 1, 2008 | 57,357 | $ | 54.50 | |||||||||||||
Granted | 12,391 | $ | 84.98 | |||||||||||||
Exercised | (10,758 | ) | $ | 53.69 | ||||||||||||
Restored | 1,196 | $ | 94.53 | |||||||||||||
Forfeited | (1,173 | ) | $ | 79.53 | ||||||||||||
Outstanding at December 31, 2008 | 59,013 | $ | 61.36 | 6.5 yrs. | $ | 883 | ||||||||||
Exercisable at December 31, 2008 | 36,934 | $ | 51.51 | 5.2 yrs. | $ | 838 | ||||||||||
The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2008, 2007 and 2006 was $433, $423 and $281, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.
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Note 21 Stock Options and Other Share-Based Compensation - Continued |
As of December 31, 2008, there was $179 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted or restored under the plans. That cost is expected to be recognized over a weighted-average period of 1.9 years.
At January 1, 2008, the number of LTIP performance units outstanding was equivalent to 2,225,015 shares. During 2008, 888,300 units were granted, 652,897 units vested with cash proceeds distributed to recipients and 59,863 units were forfeited. At December 31, 2008, units outstanding were 2,400,555, and the fair value of the liability recorded for these instruments was $201. In addition, outstanding stock appreciation rights and other awards that were granted under various LTIP and former Texaco and Unocal programs totaled approximately 1.4 million equivalent shares as of December 31, 2008. A liability of $35 was recorded for these awards.
Broad-Based Employee Stock Options In addition to the plans described above, Chevron granted all eligible employees stock options or equivalents in 1998. The options vested in February 2000 and expired in February 2008. A total of 9,641,600 options were awarded with an exercise price of $38.16 per share.
Employee Benefit Plans
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 22Employee Benefit Plans - Continued | |||||||||
Pension Benefits | ||||||||||||||||||||||||||
2008 | 2007 | Other Benefits | ||||||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | 2008 | 2007 | |||||||||||||||||||||
Change in Benefit Obligation | ||||||||||||||||||||||||||
Benefit obligation at January 1 | $ | 8,395 | $ | 4,633 | $ | 8,792 | $ | 4,207 | $ | 2,939 | $ | 3,257 | ||||||||||||||
Service cost | 250 | 132 | 260 | 125 | 44 | 49 | ||||||||||||||||||||
Interest cost | 499 | 292 | 483 | 255 | 178 | 184 | ||||||||||||||||||||
Plan participants’ contributions | – | 9 | – | 7 | 152 | 122 | ||||||||||||||||||||
Plan amendments | – | 32 | (301 | ) | 97 | – | – | |||||||||||||||||||
Curtailments | – | – | – | (12 | ) | – | – | |||||||||||||||||||
Actuarial gain | (62 | ) | (104 | ) | (131 | ) | (40 | ) | (14 | ) | (413 | ) | ||||||||||||||
Foreign currency exchange rate changes | – | (858 | ) | – | 219 | (28 | ) | 12 | ||||||||||||||||||
Benefits paid | (955 | ) | (246 | ) | (708 | ) | (225 | ) | (340 | ) | (272 | ) | ||||||||||||||
Special termination benefits | – | 1 | – | – | – | – | ||||||||||||||||||||
Benefit obligation at December 31 | 8,127 | 3,891 | 8,395 | 4,633 | 2,931 | 2,939 | ||||||||||||||||||||
Change in Plan Assets | ||||||||||||||||||||||||||
Fair value of plan assets at January 1 | 7,918 | 3,892 | 7,941 | 3,456 | – | – | ||||||||||||||||||||
Actual return on plan assets | (2,092 | ) | (655 | ) | 607 | 232 | – | – | ||||||||||||||||||
Foreign currency exchange rate changes | – | (662 | ) | – | 183 | – | – | |||||||||||||||||||
Employer contributions | 577 | 262 | 78 | 239 | 188 | 150 | ||||||||||||||||||||
Plan participants’ contributions | – | 9 | – | 7 | 152 | 122 | ||||||||||||||||||||
Benefits paid | (955 | ) | (246 | ) | (708 | ) | (225 | ) | (340 | ) | (272 | ) | ||||||||||||||
Fair value of plan assets at December 31 | 5,448 | 2,600 | 7,918 | 3,892 | – | – | ||||||||||||||||||||
Funded Status at December 31 | $ | (2,679 | ) | $ | (1,291 | ) | $ | (477 | ) | $ | (741 | ) | $ | (2,931 | ) | $ | (2,939 | ) | ||||||||
Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, 2008 and 2007, include:
Pension Benefits | ||||||||||||||||||||||||||
2008 | 2007 | Other Benefits | ||||||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | 2008 | 2007 | |||||||||||||||||||||
Deferred charges and other assets | $ | 6 | $ | 31 | $ | 181 | $ | 279 | $ | – | $ | – | ||||||||||||||
Accrued liabilities | (72 | ) | (61 | ) | (68 | ) | (55 | ) | (209 | ) | (207 | ) | ||||||||||||||
Reserves for employee benefit plans | (2,613 | ) | (1,261 | ) | (590 | ) | (965 | ) | (2,722 | ) | (2,732 | ) | ||||||||||||||
Net amount recognized at December 31 | $ | (2,679 | ) | $ | (1,291 | ) | $ | (477 | ) | $ | (741 | ) | $ | (2,931 | ) | $ | (2,939 | ) | ||||||||
Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB postretirement plans were $5,831 and $2,990 at the end of 2008 and 2007. These amounts consisted of:
Pension Benefits | ||||||||||||||||||||||||||
2008 | 2007 | Other Benefits | ||||||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | 2008 | 2007 | |||||||||||||||||||||
Net actuarial loss | $ | 3,797 | $ | 1,804 | $ | 1,539 | $ | 1,237 | $ | 410 | $ | 490 | ||||||||||||||
Prior-service (credit) costs | (68 | ) | 211 | (75 | ) | 203 | (323 | ) | (404 | ) | ||||||||||||||||
Total recognized at December 31 | $ | 3,729 | $ | 2,015 | $ | 1,464 | $ | 1,440 | $ | 87 | $ | 86 | ||||||||||||||
The accumulated benefit obligations for all U.S. and international pension plans were $7,376 and $3,273, respectively, at December 31, 2008, and $7,712 and $4,000, respectively, at December 31, 2007.
Pension Benefits | |||||||||||||||||
2008 | 2007 | ||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | ||||||||||||||
Projected benefit obligations | $ | 8,121 | $ | 2,906 | $ | 678 | $ | 1,089 | |||||||||
Accumulated benefit obligations | 7,371 | 2,539 | 638 | 926 | |||||||||||||
Fair value of plan assets | 5,436 | 1,698 | 20 | 271 | |||||||||||||
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Note 22Employee Benefit Plans - Continued |
The components of net periodic benefit cost for 2008, 2007 and 2006 and amounts recognized in other comprehensive income for 2008 and 2007 are shown in the table below. For 2008 and 2007, changes in pension plan assets and benefit obligations were recognized as changes in other comprehensive income.
Pension Benefits | ||||||||||||||||||||||||||||||||||||||
2008 | 2007 | 2006 | Other Benefits | |||||||||||||||||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | U.S. | Int’l. | 2008 | 2007 | 2006 | ||||||||||||||||||||||||||||||
Net Periodic Benefit Cost | ||||||||||||||||||||||||||||||||||||||
Service cost | $ | 250 | $ | 132 | $ | 260 | $ | 125 | $ | 234 | $ | 98 | $ | 44 | $ | 49 | $ | 35 | ||||||||||||||||||||
Interest cost | 499 | 292 | 483 | 255 | 468 | 214 | 178 | 184 | 181 | |||||||||||||||||||||||||||||
Expected return on plan assets | (593 | ) | (273 | ) | (578 | ) | (266 | ) | (550 | ) | (227 | ) | – | – | – | |||||||||||||||||||||||
Amortization of transitional assets | – | – | – | – | – | 1 | – | – | – | |||||||||||||||||||||||||||||
Amortization of prior-service (credits) costs | (7 | ) | 24 | 46 | 17 | 46 | 14 | (81 | ) | (81 | ) | (86 | ) | |||||||||||||||||||||||||
Recognized actuarial losses | 60 | 77 | 128 | 82 | 149 | 69 | 38 | 81 | 97 | |||||||||||||||||||||||||||||
Settlement losses | 306 | 2 | 65 | – | 70 | – | – | – | – | |||||||||||||||||||||||||||||
Curtailment losses | – | – | – | 3 | – | – | – | – | – | |||||||||||||||||||||||||||||
Special termination benefit recognition | – | 1 | – | – | – | – | – | – | – | |||||||||||||||||||||||||||||
Net periodic benefit cost | 515 | 255 | 404 | 216 | 417 | 169 | 179 | 233 | 227 | |||||||||||||||||||||||||||||
Changes Recognized in Other Comprehensive Income | ||||||||||||||||||||||||||||||||||||||
Net actuarial loss (gain) during period | 2,624 | 646 | (160 | ) | 31 | – | – | (42 | ) | (401 | ) | – | ||||||||||||||||||||||||||
Amortization of actuarial loss | (366 | ) | (79 | ) | (193 | ) | (82 | ) | – | – | (38 | ) | (81 | ) | – | |||||||||||||||||||||||
Prior service cost (credit) during period | – | 32 | (301 | ) | 97 | – | – | – | – | – | ||||||||||||||||||||||||||||
Amortization of prior-service credits (costs) | 7 | (24 | ) | (46 | ) | (20 | ) | – | – | 81 | 81 | – | ||||||||||||||||||||||||||
Total changes recognized in other comprehensive income | 2,265 | 575 | (700 | ) | 26 | – | – | 1 | (401 | ) | – | |||||||||||||||||||||||||||
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income | $ | 2,780 | $ | 830 | $ | (296 | ) | $ | 242 | $ | 417 | $ | 169 | $ | 180 | $ | (168 | ) | $ | 227 | ||||||||||||||||||
Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2008, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 10, 13 and 10 years, respectively. These amortization periods represent the estimated average remaining service of employees expected to receive benefits under the plans. These losses are amortized to the extent they exceed 10 percent of the higher of the projected benefit obligation or market-related value of plan assets. The amount subject to amortization is determined on a plan-by-plan basis. During 2009, the company estimates actuarial losses of $298, $103 and $28 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively. In
addition, the company estimates an additional $201 will be recognized from “Accumulated other comprehensive loss” during 2009 related to lump-sum settlement costs from U.S. pension plans.
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 22Employee Benefit Plans - Continued | |||||||||
AssumptionsThe following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:
Pension Benefits | ||||||||||||||||||||||||||||||||||||||
2008 | 2007 | 2006 | Other Benefits | |||||||||||||||||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | U.S. | Int’l. | 2008 | 2007 | 2006 | ||||||||||||||||||||||||||||||
Assumptions used to determine benefit obligations | ||||||||||||||||||||||||||||||||||||||
Discount rate | 6.3 | % | 7.5 | % | 6.3 | % | 6.7 | % | 5.8 | % | 6.0 | % | 6.3 | % | 6.3 | % | 5.8 | % | ||||||||||||||||||||
Rate of compensation increase | 4.5 | % | 6.8 | % | 4.5 | % | 6.4 | % | 4.5 | % | 6.1 | % | 4.0 | % | 4.5 | % | 4.5 | % | ||||||||||||||||||||
Assumptions used to determine net periodic benefit cost | ||||||||||||||||||||||||||||||||||||||
Discount rate1 | 6.3 | % | 6.7 | % | 5.8 | % | 6.0 | % | 5.8 | % | 5.9 | % | 6.3 | % | 5.8 | % | 5.9 | % | ||||||||||||||||||||
Expected return on plan assets | 7.8 | % | 7.4 | % | 7.8 | % | 7.5 | % | 7.8 | % | 7.4 | % | N/A | N/A | N/A | |||||||||||||||||||||||
Rate of compensation increase | 4.5 | % | 6.4 | % | 4.5 | % | 6.1 | % | 4.2 | % | 5.1 | % | 4.5 | % | 4.5 | % | 4.2 | % | ||||||||||||||||||||
Discount Rate The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality, fixed-income debt instruments. At December 31, 2008, the company selected a 6.3 percent discount rate for the major U.S. pension and postretirement plans. This rate was based on a cash flow analysis that matched estimated future benefit payments to the Citigroup Pension Discount Yield Curve as of year-end 2008. The discount rates at the end of 2007 and 2006 were 6.3 percent and 5.8 percent, respectively.
1 Percent | 1 Percent | |||||||
Increase | Decrease | |||||||
Effect on total service and interest cost components | $ | 9 | $ | (8 | ) | |||
Effect on postretirement benefit obligation | $ | 88 | $ | (75 | ) | |||
Plan Assets and Investment Strategy The company’s pension plan weighted-average asset allocations at December 31 by asset category are as follows:
U.S. | International | ||||||||||||||||
Asset Category | 2008 | 2007 | 2008 | 2007 | |||||||||||||
Equities | 52 | % | 64 | % | 47 | % | 56 | % | |||||||||
Fixed Income | 34 | % | 23 | % | 50 | % | 43 | % | |||||||||
Real Estate | 13 | % | 12 | % | 2 | % | 1 | % | |||||||||
Other | 1 | % | 1 | % | 1 | % | – | ||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | |||||||||
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Note 22Employee Benefit Plans - Continued |
Cash Contributions and Benefit Payments In 2008, the company contributed $577 and $262 to its U.S. and international pension plans, respectively. In 2009, the company expects contributions to be approximately $550 and $250 to its U.S. and international pension plans, respectively. Actual contribution amounts are dependent upon plan-investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.
The company anticipates paying other postretirement benefits of approximately $209 in 2009, as compared with $188 paid in 2008.
Pension Benefits | Other | |||||||||||
U.S. | Int’l. | Benefits | ||||||||||
2009 | $ | 853 | $ | 226 | $ | 209 | ||||||
2010 | $ | 841 | $ | 249 | $ | 216 | ||||||
2011 | $ | 849 | $ | 240 | $ | 222 | ||||||
2012 | $ | 863 | $ | 265 | $ | 225 | ||||||
2013 | $ | 874 | $ | 277 | $ | 230 | ||||||
2014–2018 | $ | 4,379 | $ | 1,746 | $ | 1,205 | ||||||
Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP).
Employee Stock Ownership Plan Within the Chevron ESIP is an employee stock ownership plan (ESOP). In 1989, Chevron established a LESOP as a constituent part of the ESOP. The LESOP provides partial prefunding of the company’s future commitments to the ESIP.
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 22Employee Benefit Plans - Continued | |||||||||
Thousands | 2008 | 2007 | ||||||
Allocated shares | 19,651 | 20,506 | ||||||
Unallocated shares | 6,366 | 7,365 | ||||||
Total LESOP shares | 26,017 | 27,871 | ||||||
Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2008, the trust contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The company intends to continue to pay its obligations under the benefit plans. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.
Employee Incentive Plans Effective January 2008, the company established the Chevron Incentive Plan (CIP), a single annual cash bonus plan for eligible employees that links awards to corporate, unit and individual performance in the prior year. This plan replaced other cash bonus programs, which primarily included the Management Incentive Plan (MIP) and the Chevron Success Sharing program. In 2008, charges to expense for cash bonuses were $757. Charges to expense for MIP were $184 and $180 in 2007 and 2006, respectively. Charges for other cash bonus programs were $431 and $329 in 2007 and 2006, respectively. Chevron also has a Long-Term Incentive Plan (LTIP) for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under LTIP consist of stock options and other share-based compensation that are described in Note 21 on page FS-49.
Note 23
Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual
Guarantees The company has issued a guarantee of approximately $600 associated with certain payments under a terminal use agreement entered into by a company affiliate. The terminal is expected to be operational by 2012. Over the approximate 16-year term of the guarantee, the maximum guarantee amount will reduce over time as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of any amounts paid under the guarantee. Chevron carries no liability for its obligation under this guarantee.
Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300. Through the end of 2008, the company paid $48 under these indemnities and continues to be obligated for possible additional indemnification payments in the future.
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Note 23 Other Contingencies and Commitments - Continued |
Securitization During 2008, the company terminated the program used to securitize downstream-related trade accounts receivable. At year-end 2007, the balance of securitized receivables was $675 million. As of December 31, 2008, the company had no other securitization arrangements in place.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2009 – $6,405; 2010 – $3,964; 2011 – $3,578; 2012 – $1,473; 2013 – $1,329; 2014 and after – $4,333. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $5,100 in 2008 $3,700 in 2007 and $3,000 in 2006.
Minority Interests The company has commitments of $469 related to minority interests in subsidiary companies.
Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination,
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Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 23Other Contingencies and Commitments - Continued | |||||||||
Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevron’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. For this range of settlement, Chevron estimates its maximum possible net before-tax liability at approximately $200, and the possible maximum net amount that could be owed to Chevron is estimated at about $150. The timing of the settlement and the exact amount within this range of estimates are uncertain.
Other Contingencies Chevron receives claims from and submits claims to customers; trading partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve.
Note 24
Asset Retirement Obligations
2008 | 2007 | 2006 | |||||||||||
Balance at January 1 | $ | 8,253 | $ | 5,773 | $ | 4,304 | |||||||
Liabilities incurred | 308 | 178 | 153 | ||||||||||
Liabilities settled | (973 | ) | (818 | ) | (387 | ) | |||||||
Accretion expense | 430 | 399 | * | 275 | |||||||||
Revisions in estimated cash flows | 1,377 | 2,721 | 1,428 | ||||||||||
Balance at December 31 | $ | 9,395 | $ | 8,253 | $ | 5,773 | |||||||
In the table above, the amounts associated with “Revisions in estimated cash flows” reflect increasing costs to abandon onshore and offshore wells, equipment and facilities, including an aggregate of $1,804 for 2006 through 2008 for the estimated costs to dismantle and abandon wells and facilities damaged by hurricanes in the U.S. Gulf of Mexico in 2005 and 2008. The long-term portion of the $9,395 balance at the end of 2008 was $8,588.
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Note 25Other Financial Information |
Other Financial Information
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Total financing interest and debt costs | $ | 256 | $ | 468 | $ | 608 | |||||||
Less: Capitalized interest | 256 | 302 | 157 | ||||||||||
Interest and debt expense | $ | – | $ | 166 | $ | 451 | |||||||
Research and development expenses | $ | 835 | $ | 562 | $ | 468 | |||||||
Foreign currency effects* | $ | 862 | $ | (352 | ) | $ | (219 | ) | |||||
* | Includes $420, $18 and $15 in 2008, 2007 and 2006, respectively, for the company’s share of equity affiliates’ foreign currency effects. |
The excess of replacement cost over the carrying value of inventories for which the Last-In, First-Out (LIFO) method is used was $9,368 and $6,958 at December 31, 2008 and 2007, respectively. Replacement cost is generally based on average acquisition costs for the year. LIFO profits of $210, $113 and $82 were included in net income for the years 2008, 2007 and 2006, respectively.
Assets Held for Sale
Earnings Per Share
Year ended December 31 | |||||||||||||
2008 | 2007 | 2006 | |||||||||||
Basic EPS Calculation | |||||||||||||
Income from operations | $ | 23,931 | $ | 18,688 | $ | 17,138 | |||||||
Add: Dividend equivalents paid on stock units | – | – | 1 | ||||||||||
Net income available to common stockholders – Basic | $ | 23,931 | $ | 18,688 | $ | 17,139 | |||||||
Weighted-average number of common shares outstanding | 2,037 | 2,117 | 2,185 | ||||||||||
Add: Deferred awards held as stock units | 1 | 1 | 1 | ||||||||||
Total weighted-average number of common shares outstanding | 2,038 | 2,118 | 2,186 | ||||||||||
Per share of common stock | |||||||||||||
Net income – Basic | $ | 11.74 | $ | 8.83 | $ | 7.84 | |||||||
Diluted EPS Calculation | |||||||||||||
Income from operations | $ | 23,931 | $ | 18,688 | $ | 17,138 | |||||||
Add: Dividend equivalents paid on stock units | – | – | 1 | ||||||||||
Add: Dilutive effects of employee stock-based awards | – | – | – | ||||||||||
Net income available to common stockholders – Diluted | $ | 23,931 | $ | 18,688 | $ | 17,139 | |||||||
Weighted-average number of common shares outstanding | 2,037 | 2,117 | 2,185 | ||||||||||
Add: Deferred awards held as stock units | 1 | 1 | 1 | ||||||||||
Add: Dilutive effect of employee stock-based awards | 12 | 14 | 11 | ||||||||||
Total weighted-average number of common shares outstanding | 2,050 | 2,132 | 2,197 | ||||||||||
Per share of common stock | |||||||||||||
Net income – Diluted | $ | 11.67 | $ | 8.77 | $ | 7.80 | |||||||
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Five-Year Financial Summary
Unaudited
Millions of dollars, except per-share amounts | 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
Statement of Income Data | |||||||||||||||||||||
Revenues and Other Income | |||||||||||||||||||||
Total sales and other operating revenues1,2 | $ | 264,958 | $ | 214,091 | $ | 204,892 | $ | 193,641 | $ | 150,865 | |||||||||||
Income from equity affiliates and other income | 8,047 | 6,813 | 5,226 | 4,559 | 4,435 | ||||||||||||||||
Total Revenues and Other Income | 273,005 | 220,904 | 210,118 | 198,200 | 155,300 | ||||||||||||||||
Total Costs and Other Deductions | 230,048 | 188,737 | 178,142 | 173,003 | 134,749 | ||||||||||||||||
Income From Continuing Operations Before Income Taxes | 42,957 | 32,167 | 31,976 | 25,197 | 20,551 | ||||||||||||||||
Income Tax Expense | 19,026 | 13,479 | 14,838 | 11,098 | 7,517 | ||||||||||||||||
Income From Continuing Operations | 23,931 | 18,688 | 17,138 | 14,099 | 13,034 | ||||||||||||||||
Income From Discontinued Operations | – | – | – | – | 294 | ||||||||||||||||
Net Income | $ | 23,931 | $ | 18,688 | $ | 17,138 | $ | 14,099 | $ | 13,328 | |||||||||||
Per Share of Common Stock3 | |||||||||||||||||||||
Income From Continuing Operations | |||||||||||||||||||||
– Basic | $ | 11.74 | $ | 8.83 | $ | 7.84 | $ | 6.58 | $ | 6.16 | |||||||||||
– Diluted | $ | 11.67 | $ | 8.77 | $ | 7.80 | $ | 6.54 | $ | 6.14 | |||||||||||
Income From Discontinued Operations | |||||||||||||||||||||
– Basic | $ | – | $ | – | $ | – | $ | – | $ | 0.14 | |||||||||||
– Diluted | $ | – | $ | – | $ | – | $ | – | $ | 0.14 | |||||||||||
Net Income2 | |||||||||||||||||||||
– Basic | $ | 11.74 | $ | 8.83 | $ | 7.84 | $ | 6.58 | $ | 6.30 | |||||||||||
– Diluted | $ | 11.67 | $ | 8.77 | $ | 7.80 | $ | 6.54 | $ | 6.28 | |||||||||||
Cash Dividends Per Share | $ | 2.53 | $ | 2.26 | $ | 2.01 | $ | 1.75 | $ | 1.53 | |||||||||||
Balance Sheet Data (at December 31) | |||||||||||||||||||||
Current assets | $ | 36,470 | $ | 39,377 | $ | 36,304 | $ | 34,336 | $ | 28,503 | |||||||||||
Noncurrent assets | 124,695 | 109,409 | 96,324 | 91,497 | 64,705 | ||||||||||||||||
Total Assets | 161,165 | 148,786 | 132,628 | 125,833 | 93,208 | ||||||||||||||||
Short-term debt | 2,818 | 1,162 | 2,159 | 739 | 816 | ||||||||||||||||
Other current liabilities | 29,205 | 32,636 | 26,250 | 24,272 | 17,979 | ||||||||||||||||
Long-term debt and capital lease obligations | 6,083 | 6,070 | 7,679 | 12,131 | 10,456 | ||||||||||||||||
Other noncurrent liabilities | 36,411 | 31,830 | 27,605 | 26,015 | 18,727 | ||||||||||||||||
Total Liabilities | 74,517 | 71,698 | 63,693 | 63,157 | 47,978 | ||||||||||||||||
Stockholders’ Equity | $ | 86,648 | $ | 77,088 | $ | 68,935 | $ | 62,676 | $ | 45,230 | |||||||||||
1 Includes excise, value-added and similar taxes: | $ | 9,846 | $ | 10,121 | $ | 9,551 | $ | 8,719 | $ | 7,968 | |||||||||||
2 Includes amounts in revenues for buy/sell contracts; associated costs are in “Total Costs and Other Deductions.” Refer also to Note 14, on page FS-43. | $ | – | $ | – | $ | 6,725 | $ | 23,822 | $ | 18,650 | |||||||||||
3 Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004. |
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Supplemental Information on Oil and Gas Producing Activities Unaudited | |||||||||
In accordance with FAS 69,Disclosures About Oil and Gas Producing Activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V
through VII present information on the company’s estimated net 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. The Africa geographic area includes activities principally in Nigeria, Angola, Chad, Republic of the Congo and Democratic Republic of the Congo. The Asia-Pacific
Table I – Costs Incurred in Exploration, Property Acquisitions and Development1
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Millions of dollars | Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | ||||||||||||||||||||||||||||||||||||
Year Ended Dec. 31, 2008 | ||||||||||||||||||||||||||||||||||||||||||||||||
Exploration | ||||||||||||||||||||||||||||||||||||||||||||||||
Wells | $ | – | $ | 477 | $ | 42 | $ | 519 | $ | 197 | $ | 312 | $ | 20 | $ | 67 | $ | 596 | $ | 1,115 | $ | – | $ | – | ||||||||||||||||||||||||
Geological and geophysical | – | 65 | 1 | 66 | 90 | 56 | 11 | 106 | 263 | 329 | – | – | ||||||||||||||||||||||||||||||||||||
Rentals and other | – | 140 | 3 | 143 | 60 | 148 | 37 | 97 | 342 | 485 | – | – | ||||||||||||||||||||||||||||||||||||
Total exploration | – | 682 | 46 | 728 | 347 | 516 | 68 | 270 | 1,201 | 1,929 | – | – | ||||||||||||||||||||||||||||||||||||
Property acquisitions2 | ||||||||||||||||||||||||||||||||||||||||||||||||
Proved | (1 | ) | 2 | 87 | 88 | – | 169 | – | – | 169 | 257 | – | – | |||||||||||||||||||||||||||||||||||
Unproved | 1 | 576 | 2 | 579 | – | 280 | – | – | 280 | 859 | – | – | ||||||||||||||||||||||||||||||||||||
Total property acquisitions | – | 578 | 89 | 667 | – | 449 | – | – | 449 | 1,116 | – | – | ||||||||||||||||||||||||||||||||||||
Development3 | 928 | 1,923 | 1,497 | 4,348 | 3,723 | 4,484 | 753 | 1,879 | 10,839 | 15,187 | 643 | 120 | ||||||||||||||||||||||||||||||||||||
Total Costs Incurred | $ | 928 | $ | 3,183 | $ | 1,632 | $ | 5,743 | $ | 4,070 | $ | 5,449 | $ | 821 | $ | 2,149 | $ | 12,489 | $ | 18,232 | $ | 643 | $ | 120 | ||||||||||||||||||||||||
Year Ended Dec. 31, 2007 | ||||||||||||||||||||||||||||||||||||||||||||||||
Exploration | ||||||||||||||||||||||||||||||||||||||||||||||||
Wells | $ | 4 | $ | 430 | $ | 18 | $ | 452 | $ | 202 | $ | 156 | $ | 3 | $ | 195 | $ | 556 | $ | 1,008 | $ | – | $ | 7 | ||||||||||||||||||||||||
Geological and geophysical | – | 59 | 14 | 73 | 136 | 48 | 11 | 98 | 293 | 366 | – | – | ||||||||||||||||||||||||||||||||||||
Rentals and other | – | 128 | 5 | 133 | 70 | 120 | 50 | 79 | 319 | 452 | – | – | ||||||||||||||||||||||||||||||||||||
Total exploration | 4 | 617 | 37 | 658 | 408 | 324 | 64 | 372 | 1,168 | 1,826 | – | 7 | ||||||||||||||||||||||||||||||||||||
Property acquisitions2 | ||||||||||||||||||||||||||||||||||||||||||||||||
Proved | 10 | 220 | 13 | 243 | 5 | 92 | – | (2 | ) | 95 | 338 | – | – | |||||||||||||||||||||||||||||||||||
Unproved | 35 | 75 | 3 | 113 | 8 | 35 | – | 24 | 67 | 180 | – | – | ||||||||||||||||||||||||||||||||||||
Total property acquisitions | 45 | 295 | 16 | 356 | 13 | 127 | – | 22 | 162 | 518 | – | – | ||||||||||||||||||||||||||||||||||||
Development3 | 1,198 | 2,237 | 1,775 | 5,210 | 4,176 | 1,897 | 620 | 1,504 | 8,197 | 13,407 | 832 | 64 | ||||||||||||||||||||||||||||||||||||
Total Costs Incurred | $ | 1,247 | $ | 3,149 | $ | 1,828 | $ | 6,224 | $ | 4,597 | $ | 2,348 | $ | 684 | $ | 1,898 | $ | 9,527 | $ | 15,751 | $ | 832 | $ | 71 | ||||||||||||||||||||||||
Year Ended Dec. 31, 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||
Exploration | ||||||||||||||||||||||||||||||||||||||||||||||||
Wells | $ | – | $ | 493 | $ | 22 | $ | 515 | $ | 151 | $ | 121 | $ | 20 | $ | 246 | $ | 538 | $ | 1,053 | $ | 25 | $ | – | ||||||||||||||||||||||||
Geological and geophysical | – | 96 | 8 | 104 | 180 | 53 | 12 | 92 | 337 | 441 | – | – | ||||||||||||||||||||||||||||||||||||
Rentals and other | – | 116 | 16 | 132 | 48 | 140 | 58 | 50 | 296 | 428 | – | – | ||||||||||||||||||||||||||||||||||||
Total exploration | – | 705 | 46 | 751 | 379 | 314 | 90 | 388 | 1,171 | 1,922 | 25 | – | ||||||||||||||||||||||||||||||||||||
Property acquisitions2 | ||||||||||||||||||||||||||||||||||||||||||||||||
Proved | 6 | 152 | – | 158 | 1 | 10 | – | 15 | 26 | 184 | – | 581 | ||||||||||||||||||||||||||||||||||||
Unproved | 1 | 47 | 10 | 58 | – | 1 | – | 135 | 136 | 194 | – | – | ||||||||||||||||||||||||||||||||||||
Total property acquisitions | 7 | 199 | 10 | 216 | 1 | 11 | – | 150 | 162 | 378 | – | 581 | ||||||||||||||||||||||||||||||||||||
Development3 | 686 | 1,632 | 868 | 3,186 | 2,890 | 1,788 | 460 | 1,019 | 6,157 | 9,343 | 671 | 25 | ||||||||||||||||||||||||||||||||||||
Total Costs Incurred | $ | 693 | $ | 2,536 | $ | 924 | $ | 4,153 | $ | 3,270 | $ | 2,113 | $ | 550 | $ | 1,557 | $ | 7,490 | $ | 11,643 | $ | 696 | $ | 606 | ||||||||||||||||||||||||
1 | Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 24, “Asset Retirement Obligations,” beginning on page FS-58. | |
2 | Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions. | |
3 | Includes $224, $99 and $160 costs incurred prior to assignment of proved reserves in 2008, 2007 and 2006, respectively. |
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Table II Capitalized Costs Related to Oil and Gas Producing Activities |
geographic area includes activities principally in Australia, Azerbaijan, Bangladesh, China, Kazakhstan, Myanmar, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the Philippines, and Thailand. The international “Other” geographic category includes activities in Argentina, Brazil, Canada, Colombia, Denmark, the Netherlands, Norway, Trinidad and Tobago, Venezuela, the United Kingdom, and
other countries. Amounts for TCO represent Chevron’s 50 percent equity share of Tengizchevroil, an exploration and production partnership in the Republic of Kazakhstan. The affiliated companies “Other” amounts are composed of the company’s equity interests in Venezuela, Angola and Russia. Refer to Note 12 beginning on page FS-41 for a discussion of the company’s major equity affiliates.
Table II - Capitalized Costs Related to Oil and Gas Producing Activities
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Millions of dollars | Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | ||||||||||||||||||||||||||||||||||||
At Dec. 31, 2008 | ||||||||||||||||||||||||||||||||||||||||||||||||
Unproved properties | $ | 810 | $ | 1,357 | $ | 328 | $ | 2,495 | $ | 294 | $ | 2,788 | $ | 651 | $ | 912 | $ | 4,645 | $ | 7,140 | $ | 113 | $ | – | ||||||||||||||||||||||||
Proved properties and related producing assets | 12,048 | 19,318 | 14,914 | 46,280 | 17,495 | 21,726 | 8,117 | 13,041 | 60,379 | 106,659 | 5,991 | 841 | ||||||||||||||||||||||||||||||||||||
Support equipment | 239 | 226 | 252 | 717 | 967 | 266 | 1,150 | 475 | 2,858 | 3,575 | 888 | – | ||||||||||||||||||||||||||||||||||||
Deferred exploratory wells | – | 602 | – | 602 | 499 | 495 | 107 | 415 | 1,516 | 2,118 | – | – | ||||||||||||||||||||||||||||||||||||
Other uncompleted projects | 405 | 3,812 | 58 | 4,275 | 4,226 | 2,490 | 875 | 1,739 | 9,330 | 13,605 | 501 | 81 | ||||||||||||||||||||||||||||||||||||
Gross Cap. Costs | 13,502 | 25,315 | 15,552 | 54,369 | 23,481 | 27,765 | 10,900 | 16,582 | 78,728 | 133,097 | 7,493 | 922 | ||||||||||||||||||||||||||||||||||||
Unproved properties valuation | 744 | 80 | 21 | 845 | 202 | 223 | 64 | 439 | 928 | 1,773 | 29 | – | ||||||||||||||||||||||||||||||||||||
Proved producing properties – Depreciation and depletion | 7,802 | 14,546 | 8,432 | 30,780 | 6,602 | 8,692 | 6,214 | 8,360 | 29,868 | 60,648 | 831 | 212 | ||||||||||||||||||||||||||||||||||||
Support equipment depreciation | 145 | 99 | 138 | 382 | 523 | 128 | 611 | 307 | 1,569 | 1,951 | 307 | – | ||||||||||||||||||||||||||||||||||||
Accumulated provisions | 8,691 | 14,725 | 8,591 | 32,007 | 7,327 | 9,043 | 6,889 | 9,106 | 32,365 | 64,372 | 1,167 | 212 | ||||||||||||||||||||||||||||||||||||
Net Capitalized Costs | $ | 4,811 | $ | 10,590 | $ | 6,961 | $ | 22,362 | $ | 16,154 | $ | 18,722 | $ | 4,011 | $ | 7,476 | $ | 46,363 | $ | 68,725 | $ | 6,326 | $ | 710 | ||||||||||||||||||||||||
At Dec. 31, 2007 | ||||||||||||||||||||||||||||||||||||||||||||||||
Unproved properties | $ | 805 | $ | 892 | $ | 353 | $ | 2,050 | $ | 314 | $ | 2,639 | $ | 630 | $ | 1,015 | $ | 4,598 | $ | 6,648 | $ | 112 | $ | – | ||||||||||||||||||||||||
Proved properties and related producing assets | 11,260 | 19,110 | 13,718 | 44,088 | 11,894 | 17,321 | 7,705 | 11,360 | 48,280 | 92,368 | 4,247 | 858 | ||||||||||||||||||||||||||||||||||||
Support equipment | 201 | 206 | 230 | 637 | 850 | 284 | 1,123 | 439 | 2,696 | 3,333 | 758 | – | ||||||||||||||||||||||||||||||||||||
Deferred exploratory wells | – | 406 | 7 | 413 | 368 | 293 | 148 | 438 | 1,247 | 1,660 | – | – | ||||||||||||||||||||||||||||||||||||
Other uncompleted projects | 308 | 3,128 | 573 | 4,009 | 6,430 | 2,049 | 593 | 1,421 | 10,493 | 14,502 | 1,633 | 55 | ||||||||||||||||||||||||||||||||||||
Gross Cap. Costs | 12,574 | 23,742 | 14,881 | 51,197 | 19,856 | 22,586 | 10,199 | 14,673 | 67,314 | 118,511 | 6,750 | 913 | ||||||||||||||||||||||||||||||||||||
Unproved properties valuation | 741 | 57 | 35 | 833 | 201 | 221 | 39 | 427 | 888 | 1,721 | 23 | – | ||||||||||||||||||||||||||||||||||||
Proved producing properties – Depreciation and depletion | 7,383 | 15,074 | 7,640 | 30,097 | 5,427 | 6,912 | 5,592 | 7,062 | 24,993 | 55,090 | 644 | 167 | ||||||||||||||||||||||||||||||||||||
Support equipment depreciation | 133 | 92 | 124 | 349 | 464 | 144 | 571 | 261 | 1,440 | 1,789 | 267 | – | ||||||||||||||||||||||||||||||||||||
Accumulated provisions | 8,257 | 15,223 | 7,799 | 31,279 | 6,092 | 7,277 | 6,202 | 7,750 | 27,321 | 58,600 | 934 | 167 | ||||||||||||||||||||||||||||||||||||
Net Capitalized Costs | $ | 4,317 | $ | 8,519 | $ | 7,082 | $ | 19,918 | $ | 13,764 | $ | 15,309 | $ | 3,997 | $ | 6,923 | $ | 39,993 | $ | 59,911 | $ | 5,816 | $ | 746 | ||||||||||||||||||||||||
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Supplemental Information on Oil and Gas Producing Activities Table IICapitalized Costs Related to Oil and Gas Producing Activities - Continued | |||||||||
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Millions of dollars | Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | ||||||||||||||||||||||||||||||||||||
At Dec. 31, 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||
Unproved properties | $ | 770 | $ | 1,007 | $ | 370 | $ | 2,147 | $ | 342 | $ | 2,373 | $ | 707 | $ | 1,082 | $ | 4,504 | $ | 6,651 | $ | 112 | $ | – | ||||||||||||||||||||||||
Proved properties and related producing assets | 9,960 | 18,464 | 12,284 | 40,708 | 9,943 | 15,486 | 7,110 | 10,461 | 43,000 | 83,708 | 2,701 | 1,096 | ||||||||||||||||||||||||||||||||||||
Support equipment | 189 | 212 | 226 | 627 | 745 | 240 | 1,093 | 364 | 2,442 | 3,069 | 611 | – | ||||||||||||||||||||||||||||||||||||
Deferred exploratory wells | – | 343 | 7 | 350 | 231 | 217 | 149 | 292 | 889 | 1,239 | – | – | ||||||||||||||||||||||||||||||||||||
Other uncompleted projects | 370 | 2,188 | – | 2,558 | 4,299 | 1,546 | 493 | 917 | 7,255 | 9,813 | 2,493 | 40 | ||||||||||||||||||||||||||||||||||||
Gross Cap. Costs | 11,289 | 22,214 | 12,887 | 46,390 | 15,560 | 19,862 | 9,552 | 13,116 | 58,090 | 104,480 | 5,917 | 1,136 | ||||||||||||||||||||||||||||||||||||
Unproved properties valuation | 738 | 52 | 29 | 819 | 189 | 74 | 14 | 337 | 614 | 1,433 | 22 | – | ||||||||||||||||||||||||||||||||||||
Proved producing properties – Depreciation and depletion | 7,082 | 14,468 | 6,880 | 28,430 | 4,794 | 5,273 | 4,971 | 6,087 | 21,125 | 49,555 | 541 | 109 | ||||||||||||||||||||||||||||||||||||
Support equipment depreciation | 125 | 111 | 130 | 366 | 400 | 102 | 522 | 238 | 1,262 | 1,628 | 242 | – | ||||||||||||||||||||||||||||||||||||
Accumulated provisions | 7,945 | 14,631 | 7,039 | 29,615 | 5,383 | 5,449 | 5,507 | 6,662 | 23,001 | 52,616 | 805 | 109 | ||||||||||||||||||||||||||||||||||||
Net Capitalized Costs | $ | 3,344 | $ | 7,583 | $ | 5,848 | $ | 16,775 | $ | 10,177 | $ | 14,413 | $ | 4,045 | $ | 6,454 | $ | 35,089 | $ | 51,864 | $ | 5,112 | $ | 1,027 | ||||||||||||||||||||||||
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Table III Results of Operations for Oil and Gas Producing Activities1 |
The company’s results of operations from oil and gas producing activities for the years 2008, 2007 and 2006 are shown in the following table. Net income from exploration and production activities as reported on page FS-39 reflects income taxes computed on an effective rate basis.
In accordance with FAS 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page FS-39.
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Millions of dollars | Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | ||||||||||||||||||||||||||||||||||||
Year Ended Dec. 31, 2008 | ||||||||||||||||||||||||||||||||||||||||||||||||
Revenues from net production | ||||||||||||||||||||||||||||||||||||||||||||||||
Sales | $ | 226 | $ | 1,543 | $ | 3,113 | $ | 4,882 | $ | 2,578 | $ | 7,030 | $ | 1,447 | $ | 4,026 | $ | 15,081 | $ | 19,963 | $ | 4,971 | $ | 1,599 | ||||||||||||||||||||||||
Transfers | 6,405 | 2,839 | 3,624 | 12,868 | 8,373 | 5,703 | 2,975 | 3,651 | 20,702 | 33,570 | – | – | ||||||||||||||||||||||||||||||||||||
Total | 6,631 | 4,382 | 6,737 | 17,750 | 10,951 | 12,733 | 4,422 | 7,677 | 35,783 | 53,533 | 4,971 | 1,599 | ||||||||||||||||||||||||||||||||||||
Production expenses excluding taxes | (1,385 | ) | (914 | ) | (1,523 | ) | (3,822 | ) | (1,228 | ) | (1,182 | ) | (1,009 | ) | (874 | ) | (4,293 | ) | (8,115 | ) | (376 | ) | (125 | ) | ||||||||||||||||||||||||
Taxes other than on income | (107 | ) | (55 | ) | (554 | ) | (716 | ) | (163 | ) | (585 | ) | (1 | ) | (47 | ) | (796 | ) | (1,512 | ) | (41 | ) | (278 | ) | ||||||||||||||||||||||||
Proved producing properties: Depreciation and depletion | (415 | ) | (926 | ) | (945 | ) | (2,286 | ) | (1,176 | ) | (1,804 | ) | (617 | ) | (1,330 | ) | (4,927 | ) | (7,213 | ) | (237 | ) | (77 | ) | ||||||||||||||||||||||||
Accretion expense2 | (29 | ) | (119 | ) | (94 | ) | (242 | ) | (60 | ) | (31 | ) | (22 | ) | (54 | ) | (167 | ) | (409 | ) | (2 | ) | (1 | ) | ||||||||||||||||||||||||
Exploration expenses | – | (330 | ) | (40 | ) | (370 | ) | (223 | ) | (243 | ) | (83 | ) | (250 | ) | (799 | ) | (1,169 | ) | – | – | |||||||||||||||||||||||||||
Unproved properties valuation | (3 | ) | (91 | ) | (20 | ) | (114 | ) | (13 | ) | (12 | ) | (25 | ) | (7 | ) | (57 | ) | (171 | ) | – | – | ||||||||||||||||||||||||||
Other income (expense)3 | (20 | ) | (383 | ) | 1,110 | 707 | (350 | ) | 298 | (64 | ) | 282 | 166 | 873 | 184 | 105 | ||||||||||||||||||||||||||||||||
Results before income taxes | 4,672 | 1,564 | 4,671 | 10,907 | 7,738 | 9,174 | 2,601 | 5,397 | 24,910 | 35,817 | 4,499 | 1,223 | ||||||||||||||||||||||||||||||||||||
Income tax expense | (1,652 | ) | (553 | ) | (1,651 | ) | (3,856 | ) | (6,051 | ) | (4,865 | ) | (1,257 | ) | (3,016 | ) | (15,189 | ) | (19,045 | ) | (1,357 | ) | (612 | ) | ||||||||||||||||||||||||
Results of ProducingOperations | $ | 3,020 | $ | 1,011 | $ | 3,020 | $ | 7,051 | $ | 1,687 | $ | 4,309 | $ | 1,344 | $ | 2,381 | $ | 9,721 | $ | 16,772 | $ | 3,142 | $ | 611 | ||||||||||||||||||||||||
Year Ended Dec. 31, 2007 | ||||||||||||||||||||||||||||||||||||||||||||||||
Revenues from net production | ||||||||||||||||||||||||||||||||||||||||||||||||
Sales | $ | 202 | $ | 1,555 | $ | 2,476 | $ | 4,233 | $ | 1,810 | $ | 6,192 | $ | 1,045 | $ | 3,012 | $ | 12,059 | $ | 16,292 | $ | 3,327 | $ | 1,290 | ||||||||||||||||||||||||
Transfers | 4,671 | 2,630 | 2,707 | 10,008 | 6,778 | 4,440 | 2,590 | 2,744 | 16,552 | 26,560 | – | – | ||||||||||||||||||||||||||||||||||||
Total | 4,873 | 4,185 | 5,183 | 14,241 | 8,588 | 10,632 | 3,635 | 5,756 | 28,611 | 42,852 | 3,327 | 1,290 | ||||||||||||||||||||||||||||||||||||
Production expenses4 excluding taxes | (1,063 | ) | (936 | ) | (1,400 | ) | (3,399 | ) | (892 | ) | (953 | ) | (892 | ) | (828 | ) | (3,565 | ) | (6,964 | ) | (248 | ) | (92 | ) | ||||||||||||||||||||||||
Taxes other than on income | (91 | ) | (53 | ) | (378 | ) | (522 | ) | (49 | ) | (292 | ) | (2 | ) | (58 | ) | (401 | ) | (923 | ) | (31 | ) | (163 | ) | ||||||||||||||||||||||||
Proved producing properties: Depreciation and depletion | (300 | ) | (1,143 | ) | (833 | ) | (2,276 | ) | (646 | ) | (1,668 | ) | (623 | ) | (980 | ) | (3,917 | ) | (6,193 | ) | (127 | ) | (94 | ) | ||||||||||||||||||||||||
Accretion expense2 | (92 | ) | 1 | (167 | ) | (258 | ) | (33 | ) | (36 | ) | (21 | ) | (27 | ) | (117 | ) | (375 | ) | (1 | ) | (2 | ) | |||||||||||||||||||||||||
Exploration expenses | – | (486 | ) | (25 | ) | (511 | ) | (267 | ) | (225 | ) | (61 | ) | (259 | ) | (812 | ) | (1,323 | ) | – | – | |||||||||||||||||||||||||||
Unproved properties valuation | (3 | ) | (102 | ) | (27 | ) | (132 | ) | (12 | ) | (150 | ) | (30 | ) | (120 | ) | (312 | ) | (444 | ) | – | – | ||||||||||||||||||||||||||
Other income (expense)3 | 3 | 2 | 31 | 36 | (447 | ) | (302 | ) | (197 | ) | 33 | (913 | ) | (877 | ) | 18 | 7 | |||||||||||||||||||||||||||||||
Results before income taxes | 3,327 | 1,468 | 2,384 | 7,179 | 6,242 | 7,006 | 1,809 | 3,517 | 18,574 | 25,753 | 2,938 | 946 | ||||||||||||||||||||||||||||||||||||
Income tax expense | (1,204 | ) | (531 | ) | (864 | ) | (2,599 | ) | (4,907 | ) | (3,456 | ) | (841 | ) | (1,830 | ) | (11,034 | ) | (13,633 | ) | (887 | ) | (462 | ) | ||||||||||||||||||||||||
Results of ProducingOperations | $ | 2,123 | $ | 937 | $ | 1,520 | $ | 4,580 | $ | 1,335 | $ | 3,550 | $ | 968 | $ | 1,687 | $ | 7,540 | $ | 12,120 | $ | 2,051 | $ | 484 | ||||||||||||||||||||||||
1 | The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. | |
2 | Represents accretion of ARO liability. Refer to Note 24, “Asset Retirement Obligations,” beginning on page FS-58. | |
3 | Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements. | |
4 | Includes $10 costs incurred prior to assignment of proved reserves in 2007. |
FS-65
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Supplemental Information on Oil and Gas Producing Activities | ||||||||||
Table III Results of Operations for Oil and Gas Producing Activities1 - Continued |
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Millions of dollars | Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | ||||||||||||||||||||||||||||||||||||
Year Ended Dec. 31, 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||
Revenues from net production | ||||||||||||||||||||||||||||||||||||||||||||||||
Sales | $ | 308 | $ | 1,845 | $ | 2,976 | $ | 5,129 | $ | 2,377 | $ | 4,938 | $ | 1,001 | $ | 2,814 | $ | 11,130 | $ | 16,259 | $ | 2,861 | $ | 598 | ||||||||||||||||||||||||
Transfers | 4,072 | 2,317 | 2,046 | 8,435 | 5,264 | 4,084 | 2,211 | 2,848 | 14,407 | 22,842 | – | – | ||||||||||||||||||||||||||||||||||||
Total | 4,380 | 4,162 | 5,022 | 13,564 | 7,641 | 9,022 | 3,212 | 5,662 | 25,537 | 39,101 | 2,861 | 598 | ||||||||||||||||||||||||||||||||||||
Production expenses excluding taxes | (889 | ) | (765 | ) | (1,057 | ) | (2,711 | ) | (640 | ) | (740 | ) | (728 | ) | (664 | ) | (2,772 | ) | (5,483 | ) | (202 | ) | (42 | ) | ||||||||||||||||||||||||
Taxes other than on income | (84 | ) | (57 | ) | (442 | ) | (583 | ) | (57 | ) | (231 | ) | (1 | ) | (60 | ) | (349 | ) | (932 | ) | (28 | ) | (6 | ) | ||||||||||||||||||||||||
Proved producing properties: | ||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation and depletion | (275 | ) | (1,096 | ) | (763 | ) | (2,134 | ) | (579 | ) | (1,475 | ) | (666 | ) | (703 | ) | (3,423 | ) | (5,557 | ) | (114 | ) | (33 | ) | ||||||||||||||||||||||||
Accretion expense2 | (11 | ) | (80 | ) | (39 | ) | (130 | ) | (26 | ) | (30 | ) | (23 | ) | (49 | ) | (128 | ) | (258 | ) | (1 | ) | – | |||||||||||||||||||||||||
Exploration expenses | – | (407 | ) | (24 | ) | (431 | ) | (296 | ) | (209 | ) | (110 | ) | (318 | ) | (933 | ) | (1,364 | ) | (25 | ) | – | ||||||||||||||||||||||||||
Unproved properties valuation | (3 | ) | (73 | ) | (8 | ) | (84 | ) | (28 | ) | (15 | ) | (14 | ) | (27 | ) | (84 | ) | (168 | ) | – | – | ||||||||||||||||||||||||||
Other income (expense)3 | 1 | (732 | ) | 254 | (477 | ) | (435 | ) | (475 | ) | 50 | 385 | (475 | ) | (952 | ) | 8 | (50 | ) | |||||||||||||||||||||||||||||
Results before income taxes | 3,119 | 952 | 2,943 | 7,014 | 5,580 | 5,847 | 1,720 | 4,226 | 17,373 | 24,387 | 2,499 | 467 | ||||||||||||||||||||||||||||||||||||
Income tax expense | (1,169 | ) | (357 | ) | (1,103 | ) | (2,629 | ) | (4,740 | ) | (3,224 | ) | (793 | ) | (2,151 | ) | (10,908 | ) | (13,537 | ) | (750 | ) | (174 | ) | ||||||||||||||||||||||||
Results of Producing Operations | $ | 1,950 | $ | 595 | $ | 1,840 | $ | 4,385 | $ | 840 | $ | 2,623 | $ | 927 | $ | 2,075 | $ | 6,465 | $ | 10,850 | $ | 1,749 | $ | 293 | ||||||||||||||||||||||||
1 | The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. | |
2 | Represents accretion of ARO liability. Refer to Note 24, “Asset Retirement Obligations,” beginning on page FS-58. | |
3 | Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements. |
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Table IVResults of Operations for Oil and Gas Producing Activities - Unit Prices and Costs1,2 |
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | |||||||||||||||||||||||||||||||||||||
Year Ended Dec. 31, 2008 | ||||||||||||||||||||||||||||||||||||||||||||||||
Average sales prices Liquids, per barrel | $ | 87.43 | $ | 95.62 | $ | 85.30 | $ | 88.43 | $ | 91.71 | $ | 86.38 | $ | 79.14 | $ | 85.14 | $ | 86.99 | $ | 87.44 | $ | 79.11 | $ | 69.65 | ||||||||||||||||||||||||
Natural gas, per thousand cubic feet | 7.19 | 9.17 | 7.43 | 7.90 | – | 4.56 | 8.25 | 6.00 | 5.14 | 6.02 | 1.56 | 3.98 | ||||||||||||||||||||||||||||||||||||
Average production costs, per barrel | 17.67 | 16.22 | 14.31 | 15.85 | 10.00 | 5.14 | 16.46 | 7.36 | 8.06 | 10.49 | 5.24 | 5.32 | ||||||||||||||||||||||||||||||||||||
Year Ended Dec. 31, 2007 | ||||||||||||||||||||||||||||||||||||||||||||||||
Average sales prices Liquids, per barrel | $ | 62.61 | $ | 65.07 | $ | 62.35 | $ | 63.16 | $ | 69.90 | $ | 64.20 | $ | 61.05 | $ | 62.97 | $ | 65.40 | $ | 64.71 | $ | 62.47 | $ | 51.98 | ||||||||||||||||||||||||
Natural gas, per thousand cubic feet | 5.77 | 7.01 | 5.65 | 6.12 | – | 3.60 | 7.61 | 4.13 | 4.02 | 4.79 | 0.89 | 0.44 | ||||||||||||||||||||||||||||||||||||
Average production costs, per barrel | 13.23 | 12.32 | 12.62 | 12.72 | 7.26 | 3.96 | 14.28 | 6.96 | 6.54 | 8.58 | 3.98 | 3.56 | ||||||||||||||||||||||||||||||||||||
Year Ended Dec. 31, 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||
Average sales prices Liquids, per barrel | $ | 55.20 | $ | 60.35 | $ | 55.80 | $ | 56.66 | $ | 61.53 | $ | 57.05 | $ | 52.23 | $ | 57.31 | $ | 57.92 | $ | 57.53 | $ | 56.80 | $ | 37.26 | ||||||||||||||||||||||||
Natural gas, per thousand cubic feet | 6.08 | 7.20 | 5.73 | 6.29 | 0.06 | 3.44 | 7.12 | 4.03 | 3.88 | 4.85 | 0.77 | 0.36 | ||||||||||||||||||||||||||||||||||||
Average production costs, per barrel | 10.94 | 9.59 | 9.26 | 9.85 | 5.13 | 3.36 | 11.44 | 5.23 | 5.17 | 6.76 | 3.31 | 2.51 | ||||||||||||||||||||||||||||||||||||
1 | The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. | |
2 | Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel. |
Table V – Reserve Quantity Information
Reserves Governance The company has adopted a comprehensive reserves and resource classification system modeled after a system developed and approved by the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The system classifies recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three noncommercial. Within the commercial classification are proved reserves and two categories of unproved: probable and possible. The noncommercial categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC and company standards.
Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.
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During the year, the RAC is represented in meetings with each of the company’s upstream business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s Strategy and Planning Committee and the Executive Committee, whose members include the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserve activity is also reviewed with the Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.
each contained between 1 percent and 5 percent of the company’s oil-equivalent proved reserves, which in the aggregate accounted for approximately 40 percent of the company’s total proved reserves. These properties were geographically dispersed, located in the United States, South America, West Africa, the Middle East and the Asia-Pacific region.
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Net Proved Reserves of Crude Oil, Condensate and Natural Gas Liquids
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Millions of barrels | Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | ||||||||||||||||||||||||||||||||||||
Reserves at Jan. 1, 20061 | 965 | 333 | 533 | 1,831 | 1,814 | 829 | 579 | 573 | 3,795 | 5,626 | 1,939 | 435 | ||||||||||||||||||||||||||||||||||||
Changes attributable to: | ||||||||||||||||||||||||||||||||||||||||||||||||
Revisions | (14 | ) | 7 | 7 | – | (49 | ) | 72 | 61 | (45 | ) | 39 | 39 | 60 | 24 | |||||||||||||||||||||||||||||||||
Improved recovery | 49 | – | 3 | 52 | 13 | 1 | 6 | 11 | 31 | 83 | – | – | ||||||||||||||||||||||||||||||||||||
Extensions and discoveries | – | 25 | 8 | 33 | 30 | 6 | 2 | 36 | 74 | 107 | – | – | ||||||||||||||||||||||||||||||||||||
Purchases2 | 2 | 2 | – | 4 | 15 | – | – | 2 | 17 | 21 | – | 119 | ||||||||||||||||||||||||||||||||||||
Sales3 | – | – | – | – | – | – | – | (15 | ) | (15 | ) | (15 | ) | – | – | |||||||||||||||||||||||||||||||||
Production | (76 | ) | (42 | ) | (51 | ) | (169 | ) | (125 | ) | (123 | ) | (72 | ) | (78 | ) | (398 | ) | (567 | ) | (49 | ) | (16 | ) | ||||||||||||||||||||||||
Reserves at Dec. 31, 20061 | 926 | 325 | 500 | 1,751 | 1,698 | 785 | 576 | 484 | 3,543 | 5,294 | 1,950 | 562 | ||||||||||||||||||||||||||||||||||||
Changes attributable to: | ||||||||||||||||||||||||||||||||||||||||||||||||
Revisions | 1 | (1 | ) | (5 | ) | (5 | ) | (89 | ) | 7 | (66 | ) | 7 | (141 | ) | (146 | ) | 92 | 11 | |||||||||||||||||||||||||||||
Improved recovery | 6 | – | 3 | 9 | 7 | 3 | 1 | – | 11 | 20 | – | – | ||||||||||||||||||||||||||||||||||||
Extensions and discoveries | 1 | 25 | 10 | 36 | 6 | 1 | – | 17 | 24 | 60 | – | – | ||||||||||||||||||||||||||||||||||||
Purchases2 | 1 | 9 | – | 10 | – | – | – | – | – | 10 | – | 316 | ||||||||||||||||||||||||||||||||||||
Sales3 | – | (8 | ) | (1 | ) | (9 | ) | – | – | – | – | – | (9 | ) | – | (432 | ) | |||||||||||||||||||||||||||||||
Production | (75 | ) | (43 | ) | (50 | ) | (168 | ) | (122 | ) | (128 | ) | (72 | ) | (74 | ) | (396 | ) | (564 | ) | (53 | ) | (24 | ) | ||||||||||||||||||||||||
Reserves at Dec. 31, 20071 | 860 | 307 | 457 | 1,624 | 1,500 | 668 | 439 | 434 | 3,041 | 4,665 | 1,989 | 433 | ||||||||||||||||||||||||||||||||||||
Changes attributable to: | ||||||||||||||||||||||||||||||||||||||||||||||||
Revisions | 10 | 4 | (30 | ) | (16 | ) | 2 | 384 | 191 | (25 | ) | 552 | 536 | 249 | 18 | |||||||||||||||||||||||||||||||||
Improved recovery | 4 | – | 1 | 5 | 1 | 17 | 1 | 3 | 22 | 27 | – | 10 | ||||||||||||||||||||||||||||||||||||
Extensions and discoveries | 1 | 13 | 3 | 17 | 3 | 3 | 2 | 8 | 16 | 33 | – | – | ||||||||||||||||||||||||||||||||||||
Purchases | – | – | 1 | 1 | – | – | – | – | – | 1 | – | – | ||||||||||||||||||||||||||||||||||||
Sales3 | – | (6 | ) | (1 | ) | (7 | ) | – | – | – | – | – | (7 | ) | – | – | ||||||||||||||||||||||||||||||||
Production | (73 | ) | (32 | ) | (49 | ) | (154 | ) | (121 | ) | (110 | ) | (66 | ) | (69 | ) | (366 | ) | (520 | ) | (62 | ) | (22 | ) | ||||||||||||||||||||||||
Reserves at Dec. 31, 20081,4 | 802 | 286 | 382 | 1,470 | 1,385 | 962 | 567 | 351 | 3,265 | 4,735 | 2,176 | 439 | ||||||||||||||||||||||||||||||||||||
Developed Reserves5 | ||||||||||||||||||||||||||||||||||||||||||||||||
At Jan. 1, 2006 | 809 | 177 | 474 | 1,460 | 945 | 534 | 439 | 416 | 2,334 | 3,794 | 1,611 | 196 | ||||||||||||||||||||||||||||||||||||
At Dec. 31, 2006 | 749 | 163 | 443 | 1,355 | 893 | 530 | 426 | 349 | 2,198 | 3,553 | 1,003 | 311 | ||||||||||||||||||||||||||||||||||||
At Dec. 31, 2007 | 701 | 136 | 401 | 1,238 | 758 | 422 | 363 | 305 | 1,848 | 3,086 | 1,273 | 263 | ||||||||||||||||||||||||||||||||||||
At Dec. 31, 2008 | 679 | 140 | 339 | 1,158 | 789 | 666 | 474 | 249 | 2,178 | 3,336 | 1,369 | 263 | ||||||||||||||||||||||||||||||||||||
1 | Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-146 for the definition of a PSC). PSC-related reserve quantities are 32 percent, 26 percent and 30 percent for consolidated companies for 2008, 2007 and 2006, respectively. | |
2 | Includes reserves acquired through nonmonetary transactions. | |
3 | Includes reserves disposed of through nonmonetary transactions. | |
4 | Net reserve changes (excluding production) in 2008 consist of 770 million barrels of developed reserves and (180) million barrels of undeveloped reserves for consolidated companies and 180 million barrels of developed reserves and 97 million barrels of undeveloped reserves for affiliated companies. | |
5 | During 2008, the percentages of undeveloped reserves at December 31, 2007, transferred to developed reserves were 18 percent and 2 percent for consolidated companies and affiliated companies, respectively. |
Information on Canadian Oil Sands Net Proved Reserves Not Included Above:
Noteworthy amounts in the categories of liquids proved-reserve changes for 2006 through 2008 are discussed below:
lion barrels in Indonesia and 27 million barrels in Thailand. In Indonesia, the increase was the result of infill drilling and improved steamflood and waterflood performance.
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year-end prices. Higher prices also resulted in downward revisions in Karachaganak and Azerbaijan. For equity affiliates, most of the upward revision was related to a 92 million-barrel increase for TCO’s Tengiz Field and an 11 million-barrel increase for Petroboscan in Venezuela, both as a result of improved reservoir performance. At TCO, the upward revision was tempered by the negative impact of higher year-end prices.
was related to gas reinjection in Kazakhstan. Affiliated companies increased reserves 10 million barrels due to improved secondary recovery at Boscan.
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Table V Reserve Quantity Information - Continued |
Net Proved Reserves of Natural Gas
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Billions of cubic feet | Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | ||||||||||||||||||||||||||||||||||||
Reserves at Jan. 1, 20061 | 304 | 1,171 | 2,953 | 4,428 | 3,191 | 8,623 | 646 | 3,578 | 16,038 | 20,466 | 2,787 | 181 | ||||||||||||||||||||||||||||||||||||
Changes attributable to: | ||||||||||||||||||||||||||||||||||||||||||||||||
Revisions | 32 | 40 | (102 | ) | (30 | ) | 34 | 400 | 38 | 39 | 511 | 481 | 26 | – | ||||||||||||||||||||||||||||||||||
Improved recovery | 5 | – | – | 5 | 3 | – | – | 5 | 8 | 13 | – | – | ||||||||||||||||||||||||||||||||||||
Extensions and discoveries | – | 111 | 157 | 268 | 11 | 510 | – | 10 | 531 | 799 | – | – | ||||||||||||||||||||||||||||||||||||
Purchases2 | 6 | 13 | – | 19 | – | 16 | – | – | 16 | 35 | – | 54 | ||||||||||||||||||||||||||||||||||||
Sales3 | – | – | (1 | ) | (1 | ) | – | – | – | (148 | ) | (148 | ) | (149 | ) | – | – | |||||||||||||||||||||||||||||||
Production | (37 | ) | (241 | ) | (383 | ) | (661 | ) | (33 | ) | (629 | ) | (110 | ) | (302 | ) | (1,074 | ) | (1,735 | ) | (70 | ) | (4 | ) | ||||||||||||||||||||||||
Reserves at Dec. 31, 20061 | 310 | 1,094 | �� | 2,624 | 4,028 | 3,206 | 8,920 | 574 | 3,182 | 15,882 | 19,910 | 2,743 | 231 | |||||||||||||||||||||||||||||||||||
Changes attributable to: | ||||||||||||||||||||||||||||||||||||||||||||||||
Revisions | 40 | 39 | 130 | 209 | (141 | ) | 149 | 12 | 166 | 186 | 395 | 75 | (2 | ) | ||||||||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | – | – | – | 1 | 1 | 1 | – | – | ||||||||||||||||||||||||||||||||||||
Extensions and discoveries | – | 40 | 46 | 86 | 11 | 392 | – | 29 | 432 | 518 | – | – | ||||||||||||||||||||||||||||||||||||
Purchases2 | 2 | 19 | 29 | 50 | – | 91 | – | – | 91 | 141 | – | 211 | ||||||||||||||||||||||||||||||||||||
Sales3 | – | (39 | ) | (37 | ) | (76 | ) | – | – | – | – | – | (76 | ) | – | (175 | ) | |||||||||||||||||||||||||||||||
Production | (35 | ) | (210 | ) | (375 | ) | (620 | ) | (27 | ) | (725 | ) | (101 | ) | (279 | ) | (1,132 | ) | (1,752 | ) | (70 | ) | (10 | ) | ||||||||||||||||||||||||
Reserves at Dec. 31, 20071 | 317 | 943 | 2,417 | 3,677 | 3,049 | 8,827 | 485 | 3,099 | 15,460 | 19,137 | 2,748 | 255 | ||||||||||||||||||||||||||||||||||||
Changes attributable to: | ||||||||||||||||||||||||||||||||||||||||||||||||
Revisions | 8 | 21 | (57 | ) | (28 | ) | 60 | 961 | 107 | 66 | 1,194 | 1,166 | 498 | 632 | ||||||||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||||||||
Extensions and discoveries | – | 95 | 13 | 108 | – | 23 | – | 1 | 24 | 132 | – | – | ||||||||||||||||||||||||||||||||||||
Purchases | – | – | 66 | 66 | – | 441 | – | – | 441 | 507 | – | – | ||||||||||||||||||||||||||||||||||||
Sales3 | – | (27 | ) | (97 | ) | (124 | ) | – | – | – | – | – | (124 | ) | – | – | ||||||||||||||||||||||||||||||||
Production | (32 | ) | (161 | ) | (356 | ) | (549 | ) | (53 | ) | (769 | ) | (117 | ) | (308 | ) | (1,247 | ) | (1,796 | ) | (71 | ) | (9 | ) | ||||||||||||||||||||||||
Reserves at Dec. 31, 20081,4 | 293 | 871 | 1,986 | 3,150 | 3,056 | 9,483 | 475 | 2,858 | 15,872 | 19,022 | 3,175 | 878 | ||||||||||||||||||||||||||||||||||||
Developed Reserves5 | ||||||||||||||||||||||||||||||||||||||||||||||||
At Jan. 1, 2006 | 251 | 977 | 2,794 | 4,022 | 1,346 | 4,819 | 449 | 2,453 | 9,067 | 13,089 | 2,314 | 85 | ||||||||||||||||||||||||||||||||||||
At Dec. 31, 2006 | 250 | 873 | 2,434 | 3,557 | 1,306 | 4,751 | 377 | 1,912 | 8,346 | 11,903 | 1,412 | 144 | ||||||||||||||||||||||||||||||||||||
At Dec. 31, 2007 | 261 | 727 | 2,238 | 3,226 | 1,151 | 5,081 | 326 | 1,915 | 8,473 | 11,699 | 1,762 | 117 | ||||||||||||||||||||||||||||||||||||
At Dec. 31, 2008 | 247 | 669 | 1,793 | 2,709 | 1,209 | 5,374 | 302 | 2,245 | 9,130 | 11,839 | 1,999 | 124 | ||||||||||||||||||||||||||||||||||||
1 | Includes year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-146 for the definition of a PSC). PSC-related reserve quantities are 40 percent, 37 percent and 47 percent for consolidated companies for 2008, 2007 and 2006, respectively. | |
2 | Includes reserves acquired through nonmonetary transactions. | |
3 | Includes reserves disposed of through nonmonetary transactions. | |
4 | Net reserve changes (excluding production) in 2008 consist of 1,936 billion cubic feet of developed reserves and (255) billion cubic feet of undeveloped reserves for consolidated companies and 324 billion cubic feet of developed reserves and 806 billion cubic feet of undeveloped reserves for affiliated companies. | |
5 | During 2008, the percentages of undeveloped reserves at December 31, 2007, transferred to developed reserves were 12 percent and 0 percent for consolidated companies and affiliated companies, respectively. |
Noteworthy amounts in the categories of natural gas proved-reserve changes for 2006 through 2008 are discussed below:
RevisionsIn 2006, revisions accounted for a net increase of 481 billion cubic feet (BCF) for consolidated companies and 26 BCF for affiliates. For consolidated companies, net increases of 511 BCF internationally were partially offset by a 30 BCF downward revision in the United States. Drilling and development activities added 337 BCF of reserves in Thailand, while Kazakhstan added 200 BCF, largely due to development activity. Trinidad and Tobago increased 185 BCF, attributable to improved reservoir performance and a
new contract for sales of natural gas. These additions were partially offset by downward revisions of 224 BCF in the United Kingdom and 130 BCF in Australia due to drilling results and reservoir performance. U.S. “Other” had a downward revision of 102 BCF due to reservoir performance, which was partially offset by upward revisions of 72 BCF in the Gulf of Mexico and California related to reservoir performance and development drilling. TCO had an upward revision of 26 BCF associated with additional development activity and updated reservoir performance.
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Table V Reserve Quantity Information - Continued |
ated companies by a net 73 BCF. For consolidated companies, net increases were 209 BCF in the United States and 186 BCF internationally. Improved reservoir performance for many fields in the United States contributed 130 BCF in the “Other” region, 40 BCF in California and 39 BCF in the Gulf of Mexico. Drilling activities added 360 BCF in Thailand and improved reservoir performance added 188 BCF in Trinidad and Tobago. These additions were partially offset by downward revisions of 185 BCF in Australia due to drilling results and 136 BCF in Nigeria due to field performance. Negative revisions due to the impact of higher prices were recorded in Azerbaijan and Kazakhstan. TCO had an upward revision of 75 BCF associated with improved reservoir performance and development activities. This upward revision was net of a negative impact due to higher year-end prices.
In 2007, purchases of natural gas reserves were 141 BCF for consolidated companies, which include the acquisition of an additional interest in the Bibiyana Field in Bangladesh. Affiliated company purchases of 211 BCF related to the formation of a new Hamaca equity affiliate in Venezuela and an initial booking related to the Angola LNG project.
Table VI – Standardized Measure of Discounted Future
Net Cash Flows Related to Proved Oil
and Gas Reserves
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Table VIStandardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves |
Consolidated Companies | ||||||||||||||||||||||||||||||||||||||||||||||||
United States | International | |||||||||||||||||||||||||||||||||||||||||||||||
Gulf of | Total | Asia- | Total | Affiliated Companies | ||||||||||||||||||||||||||||||||||||||||||||
Millions of dollars | Calif. | Mexico | Other | U.S. | Africa | Pacific | Indonesia | Other | Int’l. | Total | TCO | Other | ||||||||||||||||||||||||||||||||||||
At December 31, 2008 | ||||||||||||||||||||||||||||||||||||||||||||||||
Future cash inflows from production | $ | 27,223 | $ | 16,407 | $ | 22,544 | $ | 66,174 | $ | 52,344 | $ | 67,386 | $ | 22,836 | $ | 23,041 | $ | 165,607 | $ | 231,781 | $ | 51,252 | $ | 13,968 | ||||||||||||||||||||||||
Future production costs | (20,554 | ) | (8,311 | ) | (16,873 | ) | (45,738 | ) | (20,302 | ) | (21,949 | ) | (17,857 | ) | (9,374 | ) | (69,482 | ) | (115,220 | ) | (14,502 | ) | (2,319 | ) | ||||||||||||||||||||||||
Future devel. costs | (3,087 | ) | (1,650 | ) | (1,362 | ) | (6,099 | ) | (19,001 | ) | (12,575 | ) | (3,632 | ) | (2,499 | ) | (37,707 | ) | (43,806 | ) | (10,140 | ) | (1,551 | ) | ||||||||||||||||||||||||
Future income taxes | (1,272 | ) | (2,289 | ) | (1,530 | ) | (5,091 | ) | (9,581 | ) | (11,906 | ) | (613 | ) | (5,352 | ) | (27,452 | ) | (32,543 | ) | (7,517 | ) | (5,223 | ) | ||||||||||||||||||||||||
Undiscounted future net cash flows | 2,310 | 4,157 | 2,779 | 9,246 | 3,460 | 20,956 | 734 | 5,816 | 30,966 | 40,212 | 19,093 | 4,875 | ||||||||||||||||||||||||||||||||||||
10 percent midyear annual discount for timing of estimated cash flows | (1,118 | ) | (583 | ) | (617 | ) | (2,318 | ) | (1,139 | ) | (9,145 | ) | (352 | ) | (1,597 | ) | (12,233 | ) | (14,551 | ) | (11,261 | ) | (2,966 | ) | ||||||||||||||||||||||||
Standardized Measure | ||||||||||||||||||||||||||||||||||||||||||||||||
Net Cash Flows | $ | 1,192 | $ | 3,574 | $ | 2,162 | $ | 6,928 | $ | 2,321 | $ | 11,811 | $ | 382 | $ | 4,219 | $ | 18,733 | $ | 25,661 | $ | 7,832 | $ | 1,909 | ||||||||||||||||||||||||
At December 31, 2007 | ||||||||||||||||||||||||||||||||||||||||||||||||
Future cash inflows from production | $ | 75,201 | $ | 34,162 | $ | 52,775 | $ | 162,138 | $ | 132,450 | $ | 93,046 | $ | 35,020 | $ | 45,566 | $ | 306,082 | $ | 468,220 | $ | 159,078 | $ | 29,845 | ||||||||||||||||||||||||
Future production costs | (17,888 | ) | (7,193 | ) | (16,780 | ) | (41,861 | ) | (15,707 | ) | (16,022 | ) | (18,270 | ) | (11,990 | ) | (61,989 | ) | (103,850 | ) | (10,408 | ) | (1,529 | ) | ||||||||||||||||||||||||
Future devel. costs | (3,491 | ) | (3,011 | ) | (1,578 | ) | (8,080 | ) | (11,516 | ) | (8,263 | ) | (4,012 | ) | (3,468 | ) | (27,259 | ) | (35,339 | ) | (8,580 | ) | (1,175 | ) | ||||||||||||||||||||||||
Future income taxes | (19,112 | ) | (8,507 | ) | (12,221 | ) | (39,840 | ) | (74,172 | ) | (26,838 | ) | (5,796 | ) | (15,524 | ) | (122,330 | ) | (162,170 | ) | (39,575 | ) | (13,600 | ) | ||||||||||||||||||||||||
Undiscounted future net cash flows | 34,710 | 15,451 | 22,196 | 72,357 | 31,055 | 41,923 | 6,942 | 14,584 | 94,504 | 166,861 | 100,515 | 13,541 | ||||||||||||||||||||||||||||||||||||
10 percent midyear annual discount for timing of estimated cash flows | (17,204 | ) | (4,438 | ) | (9,491 | ) | (31,133 | ) | (14,171 | ) | (17,117 | ) | (2,702 | ) | (4,689 | ) | (38,679 | ) | (69,812 | ) | (64,519 | ) | (7,779 | ) | ||||||||||||||||||||||||
Standardized Measure Net Cash Flows | $ | 17,506 | $ | 11,013 | $ | 12,705 | $ | 41,224 | $ | 16,884 | $ | 24,806 | $ | 4,240 | $ | 9,895 | $ | 55,825 | $ | 97,049 | $ | 35,996 | $ | 5,762 | ||||||||||||||||||||||||
At December 31, 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||
Future cash inflows from production | $ | 48,828 | $ | 23,768 | $ | 38,727 | $ | 111,323 | $ | 97,571 | $ | 70,288 | $ | 30,538 | $ | 36,272 | $ | 234,669 | $ | 345,992 | $ | 104,069 | $ | 20,644 | ||||||||||||||||||||||||
Future production costs | (14,791 | ) | (6,750 | ) | (12,845 | ) | (34,386 | ) | (12,523 | ) | (13,398 | ) | (16,281 | ) | (10,777 | ) | (52,979 | ) | (87,365 | ) | (7,796 | ) | (2,348 | ) | ||||||||||||||||||||||||
Future devel. costs | (3,999 | ) | (2,947 | ) | (1,399 | ) | (8,345 | ) | (9,648 | ) | (6,963 | ) | (2,284 | ) | (3,082 | ) | (21,977 | ) | (30,322 | ) | (7,026 | ) | (1,732 | ) | ||||||||||||||||||||||||
Future income taxes | (10,171 | ) | (4,764 | ) | (8,290 | ) | (23,225 | ) | (53,214 | ) | (20,633 | ) | (5,448 | ) | (11,164 | ) | (90,459 | ) | (113,684 | ) | (25,212 | ) | (8,282 | ) | ||||||||||||||||||||||||
Undiscounted future net cash flows | 19,867 | 9,307 | 16,193 | 45,367 | 22,186 | 29,294 | 6,525 | 11,249 | 69,254 | 114,621 | 64,035 | 8,282 | ||||||||||||||||||||||||||||||||||||
10 percent midyear annual discount for timing of estimated cash flows | (9,779 | ) | (3,256 | ) | (7,210 | ) | (20,245 | ) | (10,065 | ) | (12,457 | ) | (2,426 | ) | (3,608 | ) | (28,556 | ) | (48,801 | ) | (40,597 | ) | (5,185 | ) | ||||||||||||||||||||||||
Standardized Measure Net Cash Flows | $ | 10,088 | $ | 6,051 | $ | 8,983 | $ | 25,122 | $ | 12,121 | $ | 16,837 | $ | 4,099 | $ | 7,641 | $ | 40,698 | $ | 65,820 | $ | 23,438 | $ | 3,097 | ||||||||||||||||||||||||
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Supplemental Information on Oil and Gas Producing Activities | ||||||||||
Table VII Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves |
The changes in present values between years, which can be significant, reflect changes in estimated proved-reserve quantities and prices and assumptions used in forecasting
production volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.”
Consolidated Companies | Affiliated Companies | |||||||||||||||||||||||||
Millions of dollars | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | ||||||||||||||||||||
Present Value at January 1 | $ | 97,049 | $ | 65,820 | $ | 84,287 | $ | 41,758 | $ | 26,535 | $ | 26,769 | ||||||||||||||
Sales and transfers of oil and gas produced net of production costs | (43,906 | ) | (34,957 | ) | (32,690 | ) | (5,750 | ) | (4,084 | ) | (3,180 | ) | ||||||||||||||
Development costs incurred | 13,682 | 10,468 | 8,875 | 763 | 889 | 721 | ||||||||||||||||||||
Purchases of reserves | 233 | 780 | 580 | – | 7,711 | 1,767 | ||||||||||||||||||||
Sales of reserves | (542 | ) | (425 | ) | (306 | ) | – | (7,767 | ) | – | ||||||||||||||||
Extensions, discoveries and improved recovery less related costs | 646 | 3,664 | 4,067 | 83 | – | – | ||||||||||||||||||||
Revisions of previous quantity estimates | 37,853 | (7,801 | ) | 7,277 | 3,718 | (1,333 | ) | (967 | ) | |||||||||||||||||
Net changes in prices, development and production costs | (169,046 | ) | 74,900 | (24,725 | ) | (51,696 | ) | 23,616 | (837 | ) | ||||||||||||||||
Accretion of discount | 17,458 | 12,196 | 14,218 | 5,976 | 3,745 | 3,673 | ||||||||||||||||||||
Net change in income tax | 72,234 | (27,596 | ) | 4,237 | 14,889 | (7,554 | ) | (1,411 | ) | |||||||||||||||||
Net change for the year | (71,388 | ) | 31,229 | (18,467 | ) | (32,017 | ) | 15,223 | (234 | ) | ||||||||||||||||
Present Value at December 31 | $ | 25,661 | $ | 97,049 | $ | 65,820 | $ | 9,741 | $ | 41,758 | $ | 26,535 | ||||||||||||||
FS-74
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Exhibit No. | Description | |||
3 | .1 | Restated Certificate of Incorporation of Chevron Corporation, dated May 30, 2008, filed as Exhibit 3.1 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2008, and incorporated herein by reference. | ||
3 | .2 | By-Laws of Chevron Corporation, as amended January 30, 2008, filed as Exhibit 3.1 to Chevron Corporation’s Current Report onForm 8-K dated February 1, 2008, and incorporated herein by reference. | ||
4 | .1 | Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request. | ||
4 | .2* | Confidential Stockholder Voting Policy of Chevron Corporation (page E-3). | ||
10 | .1* | Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan (pages E-4 to E-16). | ||
10 | .2* | Chevron Incentive Plan (pages E-17 to E-30). | ||
10 | .3* | Long-Term Incentive Plan of Chevron Corporation (pages E-31 to E-57). | ||
10 | .4 | Chevron Corporation Deferred Compensation Plan for Management Employees, as amended and restated on December 7, 2005, filed as Exhibit 10.5 to Chevron Corporation’s Current Report onForm 8-K dated December 7, 2005, and incorporated herein by reference. | ||
10 | .5* | Chevron Corporation Deferred Compensation Plan for Management Employees II (pages E-58 to E-71). | ||
10 | .6* | Chevron Corporation Retirement Restoration Plan (pages E-72 to E-98). | ||
10 | .7* | Chevron Corporation ESIP Restoration Plan (pages E-99 to E-120). | ||
10 | .8 | Texaco Inc. Stock Incentive Plan, adopted May 9, 1989, as amended May 13, 1993, and May 13, 1997, filed as Exhibit 10.13 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference. | ||
10 | .9 | Supplemental Pension Plan of Texaco Inc., dated June 26, 1975, filed as Exhibit 10.14 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference. | ||
10 | .10 | Supplemental Bonus Retirement Plan of Texaco Inc., dated May 1, 1981, filed as Exhibit 10.15 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference. | ||
10 | .11 | Texaco Inc. Director and Employee Deferral Plan approved March 28, 1997, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference. | ||
10 | .12 | Chevron Corporation 1998 Stock Option Program for U.S. Dollar Payroll Employees, filed as Exhibit 10.12 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2002, and incorporated herein by reference. | ||
10 | .13* | Summary of Chevron Incentive Plan Award Criteria (pages E-121 to E-122). | ||
10 | .14 | Chevron Corporation Change in Control Surplus Employee Severance Program for Salary Grades 41 through 43, filed as Exhibit 10.1 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference. | ||
10 | .15 | Chevron Corporation Benefit Protection Program, filed as Exhibit 10.2 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference. | ||
10 | .16 | Form of Notice of Grant under the Chevron Corporation Long-Term Incentive Plan, filed as Exhibit 10.1 to Chevron’s Current Report onForm 8-K dated June 29, 2005, and incorporated herein by reference. | ||
10 | .17 | Form of Restricted Stock Unit Grant Agreement under the Chevron Corporation Long-Term Incentive Plan, filed as Exhibit 10.20 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2006, and incorporated herein by reference. | ||
10 | .18 | Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.2 to Chevron’s Current Report onForm 8-K dated June 29, 2005, and incorporated herein by reference. | ||
10 | .19* | Form of Stock Units Agreement under Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan (page E-123). | ||
12 | .1* | Computation of Ratio of Earnings to Fixed Charges(page E-124). |
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Exhibit No. | Description | |||
21 | .1* | Subsidiaries of Chevron Corporation (pagesE-125 toE-127). | ||
23 | .1* | Consent of PricewaterhouseCoopers LLP(page E-128). | ||
24 | .1 to 24.13* | Powers of Attorney for directors and certain officers of Chevron Corporation, authorizing the signing of the Annual Report onForm 10-K on their behalf (pages E-129 to E-141). | ||
31 | .1* | Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Executive Officer(page E-142). | ||
31 | .2* | Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Financial Officer(page E-143). | ||
32 | .1* | Section 1350 Certification of the company’s Chief Executive Officer(page E-144). | ||
32 | .2* | Section 1350 Certification of the company’s Chief Financial Officer(page E-145). | ||
99 | .1* | Definitions of Selected Energy and Financial Terms (pagesE-146 toE-148). | ||
100 | .INS* | XBRL Instance Document | ||
100 | .SCH* | XBRL Schema Document | ||
100 | .CAL* | XBRL Calculation Linkbase Document | ||
100 | .LAB* | XBRL Label Linkbase Document | ||
100 | .PRE* | XBRL Presentation Linkbase Document | ||
100 | .DEF* | XBRL Definition Linkbase Document |
* | Filed herewith. |
E-2