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 |
1
2
Item 1. | Business |
(a) | General Development of Business |
3
4
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. |
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) | ||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
United States | 717 | 671 | 484 | 421 | 1,399 | 1,501 | ||||||||||||||||||
Africa: | ||||||||||||||||||||||||
Nigeria | 232 | 154 | 225 | 142 | 48 | 72 | ||||||||||||||||||
Angola | 150 | 154 | 141 | 145 | 49 | 52 | ||||||||||||||||||
Chad | 27 | 29 | 26 | 28 | 5 | 5 | ||||||||||||||||||
Republic of the Congo | 21 | 13 | 19 | 11 | 13 | 12 | ||||||||||||||||||
Democratic Republic of the Congo | 3 | 2 | 3 | 2 | 1 | 1 | ||||||||||||||||||
Total Africa | 433 | 352 | 414 | 328 | 116 | 142 | ||||||||||||||||||
Asia: | ||||||||||||||||||||||||
Indonesia | 243 | 235 | 199 | 182 | 268 | 319 | ||||||||||||||||||
Thailand | 198 | 217 | 65 | 67 | 794 | 894 | ||||||||||||||||||
Partitioned Zone (PZ)3 | 105 | 106 | 101 | 103 | 21 | 20 | ||||||||||||||||||
Kazakhstan | 69 | 66 | 42 | 41 | 161 | 153 | ||||||||||||||||||
Bangladesh | 66 | 71 | 2 | 2 | 387 | 414 | ||||||||||||||||||
Azerbaijan | 30 | 29 | 28 | 28 | 10 | 7 | ||||||||||||||||||
Philippines | 27 | 26 | 4 | 5 | 137 | 128 | ||||||||||||||||||
China | 19 | 22 | 17 | 19 | 16 | 22 | ||||||||||||||||||
Myanmar | 13 | 15 | — | — | 76 | 89 | ||||||||||||||||||
Total Asia | 770 | 787 | 458 | 447 | 1,870 | 2,046 | ||||||||||||||||||
Other: | ||||||||||||||||||||||||
United Kingdom | 110 | 106 | 73 | 71 | 222 | 208 | ||||||||||||||||||
Australia | 108 | 96 | 35 | 34 | 434 | 376 | ||||||||||||||||||
Denmark | 55 | 61 | 35 | 37 | 119 | 142 | ||||||||||||||||||
Colombia | 41 | 35 | — | — | 245 | 209 | ||||||||||||||||||
Argentina | 38 | 44 | 33 | 37 | 27 | 45 | ||||||||||||||||||
Trinidad and Tobago | 34 | 32 | 1 | — | 199 | 189 | ||||||||||||||||||
Canada | 28 | 37 | 27 | 36 | 4 | 4 | ||||||||||||||||||
Netherlands | 9 | 9 | 2 | 2 | 41 | 40 | ||||||||||||||||||
Norway | 5 | 6 | 5 | 6 | 1 | 1 | ||||||||||||||||||
Brazil | 2 | — | 2 | — | — | — | ||||||||||||||||||
Total Other | 430 | 426 | 213 | 223 | 1,292 | 1,214 | ||||||||||||||||||
Total Consolidated Operations | 2,350 | 2,236 | 1,569 | 1,419 | 4,677 | 4,903 | ||||||||||||||||||
Equity Affiliates4 | 328 | 267 | 277 | 230 | 312 | 222 | ||||||||||||||||||
Total Including Affiliates5 | 2,678 | 2,503 | 1,846 | 1,649 | 4,989 | 5,125 | ||||||||||||||||||
1 2008 conformed to 2009 geographic presentation. | ||||||||||||||||||||||||
2 Excludes Athabasca oil sands production, net: | 26 | 27 | 26 | 27 | — | — | ||||||||||||||||||
3 Located between Saudi Arabia and Kuwait. | ||||||||||||||||||||||||
4 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil (TCO) in Kazakhstan and Petroboscan, Petroindependiente and Petropiar in Venezuela. | ||||||||||||||||||||||||
5 Volumes include natural gas consumed in operations of 521 million and 520 million cubic feet per day in 2009 and 2008, respectively. |
5
5
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 |
Productive2,3 | Productive2 | |||||||||||||||
Oil Wells | Gas Wells | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
United States | 49,761 | 32,720 | 11,567 | 5,671 | ||||||||||||
Africa | 2,292 | 766 | 17 | 7 | ||||||||||||
Asia | 10,580 | 9,106 | 2,336 | 1,510 | ||||||||||||
Other | 1,605 | 963 | 275 | 74 | ||||||||||||
Total Consolidated Companies | 64,238 | 43,555 | 14,195 | 7,262 | ||||||||||||
Equity in Affiliates | 1,133 | 403 | 7 | 2 | ||||||||||||
Total Including Affiliates | 65,371 | 43,958 | 14,202 | 7,264 | ||||||||||||
Multiple completion wells included above: | 929 | 596 | 390 | 313 |
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. | |
3 | Canadian synthetic oil is not produced through wells and therefore is not presented in the table above. |
6
2008 | 2007 | 2006 | 2009 | 2008 | 2007 | |||||||||||||||||||
Liquids* — Millions of barrels | ||||||||||||||||||||||||
Consolidated Companies | 4,735 | 4,665 | 5,294 | 4,610 | 4,735 | 4,665 | ||||||||||||||||||
Affiliated Companies | 2,615 | 2,422 | 2,512 | 2,363 | 2,615 | 2,422 | ||||||||||||||||||
Natural Gas — Billions of cubic feet | ||||||||||||||||||||||||
Consolidated Companies | 19,022 | 19,137 | 19,910 | 22,153 | 19,022 | 19,137 | ||||||||||||||||||
Affiliated Companies | 4,053 | 3,003 | 2,974 | 3,896 | 4,053 | 3,003 | ||||||||||||||||||
Total Oil-Equivalent — Millions of barrels | ||||||||||||||||||||||||
Consolidated Companies | 7,905 | 7,855 | 8,612 | 8,303 | 7,905 | 7,855 | ||||||||||||||||||
Affiliated Companies | 3,291 | 2,922 | 3,008 | 3,012 | 3,291 | 2,922 |
* | Crude oil, condensate and natural gas liquids. 2009 liquids amount for consolidated companies includes 460 million barrels of synthetic oil produced from oil sands mining operations in Canada in accordance with the adoption of the new SEC definition of oil and gas producing activity. |
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 | ||||||||||||||||||
Developed and | ||||||||||||||||||||||||
Undeveloped3 | Developed3 | Undeveloped | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
United States | 4,679 | 3,708 | 6,139 | 3,769 | 10,818 | 7,477 | ||||||||||||||||||
Africa | 9,663 | 5,705 | 2,499 | 917 | 12,162 | 6,622 | ||||||||||||||||||
Asia | 38,370 | 18,491 | 5,313 | 2,742 | 43,683 | 21,233 | ||||||||||||||||||
Other | 53,181 | 26,407 | 3,243 | 792 | 56,424 | 27,199 | ||||||||||||||||||
Total Consolidated Companies | 105,893 | 54,311 | 17,194 | 8,220 | 123,087 | 62,531 | ||||||||||||||||||
Equity in Affiliates | 640 | 300 | 259 | 104 | 899 | 404 | ||||||||||||||||||
Total Including Affiliates | 106,533 | 54,611 | 17,453 | 8,324 | 123,986 | 62,935 | ||||||||||||||||||
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 | Table does not include mining acreage associated with the synthetic oil production in Canada. At year-end 2009, undeveloped gross and net acreage totaled 235 and 31, respectively. Developed gross and net acreage totaled 35 and 7, respectively. Developed acreage is acreage associated with productive mines. Undeveloped acreage is acreage on which mines have not been established and that may contain undeveloped proved reserves. | |
3 | 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 |
7
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 | ||||||||||||||||||||||||
Wells Drilling | Net Wells Completed1,2 | |||||||||||||||||||||||||||||||
at 12/31/093 | 2009 | 2008 | 2007 | |||||||||||||||||||||||||||||
Gross | Net | Prod. | Dry | Prod. | Dry | Prod. | Dry | |||||||||||||||||||||||||
United States | 47 | 22 | 582 | 3 | 846 | 4 | 875 | 5 | ||||||||||||||||||||||||
Africa | 6 | 2 | 40 | — | 33 | — | 43 | — | ||||||||||||||||||||||||
Asia | 38 | 22 | 580 | — | 665 | 1 | 597 | — | ||||||||||||||||||||||||
Other | 11 | 4 | 43 | — | 41 | — | 52 | — | ||||||||||||||||||||||||
Total Consolidated Companies | 102 | 50 | 1,245 | 3 | 1,585 | 5 | 1,567 | 5 | ||||||||||||||||||||||||
Equity in Affiliates | 1 | — | 6 | — | 16 | — | 3 | — | ||||||||||||||||||||||||
Total Including Affiliates | 103 | 50 | 1,251 | 3 | 1,601 | 5 | 1,570 | 5 | ||||||||||||||||||||||||
1 | 2008 and 2007 conformed to 2009 geographic 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. | |
Represents wells in the process of drilling, including wells for which drilling was not completed and which were temporarily suspended at the end of |
8
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 | ||||||||||||||||||||||||
Wells Drilling | Net Wells Completed1,2 | |||||||||||||||||||||||||||||||
at 12/31/093 | 2009 | 2008 | 2007 | |||||||||||||||||||||||||||||
Gross | Net | Prod. | Dry | Prod. | Dry | Prod. | Dry | |||||||||||||||||||||||||
United States | 3 | 1 | 4 | 5 | 8 | 2 | 4 | 8 | ||||||||||||||||||||||||
Africa | 6 | 2 | 2 | 1 | 2 | 1 | 6 | 2 | ||||||||||||||||||||||||
Asia | 1 | — | 9 | 1 | 9 | 2 | 13 | 9 | ||||||||||||||||||||||||
Other | 4 | 3 | 5 | 4 | 44 | 2 | 43 | 6 | ||||||||||||||||||||||||
Total Consolidated Companies | 14 | 6 | 20 | 11 | 63 | 7 | 66 | 25 | ||||||||||||||||||||||||
Equity in Affiliates | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Total Including Affiliates | 14 | 6 | 20 | 11 | 63 | 7 | 66 | 25 | ||||||||||||||||||||||||
1 | 2008 and 2007 conformed to | |
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 |
9
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 |
During 2009, Chevron was engaged in various development and exploration activities in the deepwater Gulf of At the 58 percent-owned and operated Tahiti Field, first oil was achieved in the second quarter 2009. Maximum total production of 135,000 barrels per day of oil-equivalent was achieved in the third quarter 2009. A second development phase is under evaluation, including additional development drilling and a probable waterflood, with |
10
10
• | ||
Buckskin — 55 percent-owned and operated. A successful wildcat discovery was announced in February 2009. The first appraisal well | ||
• | Knotty Head — 25 | |
• | Puma — | |
• | Tubular Bells — 30 |
11
11
b) | Africa |
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 The company operates |
12
12
Nigeria:Chevron holds a 40 percent interest in 13 concessions In deepwater Also in the deepwater area, t he Aparo Field in OML 132 and OML 140 and the Bonga SW Field in offshore OML 118 share a common geologic structure and are planned to be |
13
13
14
15
Azerbaijan: Chevron holds a In Kazakhstan: Chevron holds a 20 |
15
16
Thailand: Chevron has operated and nonoperated working interests in several different offshore blocks. The company’s net oil-equivalent production in 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 |
16
17
China: Chevron has one operated and three nonoperated working interests in several areas. Net oil-equivalent production from the nonoperated areas in The company holds a 49 In the South China Sea, the company has nonoperated working interests of |
17
18
Chevron’s operated interests in Indonesia are managed by several wholly owned subsidiaries, including |
1918
Partitioned Zone (PZ): Chevron holds a During 2009, the company’s average net oil-equivalent production was 105,000 barrels per day, composed of 101,000 barrels of crude oil and 21 million cubic feet of natural gas. In June 2009, steam injection was initiated in the second phase of a steamflood pilot project. |
Australia: During 2009, the average net oil-equivalent production from Chevron’s interests in Australia was 108,000 barrels per day, composed of 35,000 barrels of liquids and 434 million cubic feet of natural gas. Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2009 averaged 26,000 barrels of crude oil and condensate, 433 million cubic feet of natural gas, and 5,000 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. The NWS Venture continues to progress two major capital projects that achieved final investment decision in 2008. Fabrication of platform topsides for the North Rankin 2 project commenced in June 2009. The proj ect is designed to recover remaining low-pressure natural gas from the North Rankin and Perseus natural-gas fields to meet gas supply needs and includes necessary tie-ins to, and refurbishment of, the North Rankin A platform. Upon completion, both platforms are |
19
20
Argentina: Chevron holds operated interests in Brazil: Chevron holds working interests In the partner-operated Campos Basin Block BC-20, two areas — |
21
20
Canada: Company activities in Canada include nonoperated working interests of Substantially all of this production was from the Hibernia Field, where | ||||
22
21
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 Faroe Islands: Chevron Netherlands: Chevron |
22
23
23
December 31, 2008 | December 31, 2009 | |||||||||||||||||||||||||||||||||||||||||||
Operable | Refinery Inputs | Operable | Refinery Inputs | |||||||||||||||||||||||||||||||||||||||||
Locations | Locations | Number | Capacity | 2008 | 2007 | 2006 | Locations | Number | Capacity | 2009 | 2008 | 2007 | ||||||||||||||||||||||||||||||||
Pascagoula | Mississippi | 1 | 330 | 299 | 285 | 337 | Mississippi | 1 | 330 | 345 | 299 | 285 | ||||||||||||||||||||||||||||||||
El Segundo | California | 1 | 265 | 263 | 222 | 258 | California | 1 | 269 | 247 | 263 | 222 | ||||||||||||||||||||||||||||||||
Richmond | California | 1 | 243 | 237 | 192 | 224 | California | 1 | 243 | 218 | 237 | 192 | ||||||||||||||||||||||||||||||||
Kapolei | Hawaii | 1 | 54 | 46 | 51 | 50 | Hawaii | 1 | 54 | 49 | 46 | 51 | ||||||||||||||||||||||||||||||||
Salt Lake City | Utah | 1 | 45 | 38 | 42 | 39 | Utah | 1 | 45 | 40 | 38 | 42 | ||||||||||||||||||||||||||||||||
Other1 | 1 | 80 | 8 | 20 | 31 | |||||||||||||||||||||||||||||||||||||||
Perth Amboy1 | New Jersey | 1 | 80 | — | 8 | 20 | ||||||||||||||||||||||||||||||||||||||
Total Consolidated Companies —United States | Total Consolidated Companies —United States | 6 | 1,017 | 891 | 812 | 939 | Total Consolidated Companies— United States | 6 | 1,021 | 899 | 891 | 812 | ||||||||||||||||||||||||||||||||
Pembroke | United Kingdom | 1 | 210 | 203 | 212 | 165 | United Kingdom | 1 | 210 | 205 | 203 | 212 | ||||||||||||||||||||||||||||||||
Cape Town2 | South Africa | 1 | 110 | 75 | 72 | 71 | South Africa | 1 | 110 | 72 | 75 | 72 | ||||||||||||||||||||||||||||||||
Burnaby, B.C. | Canada | 1 | 55 | 36 | 49 | 49 | Canada | 1 | 55 | 49 | 36 | 49 | ||||||||||||||||||||||||||||||||
Total Consolidated Companies —International | Total Consolidated Companies —International | 3 | 375 | 314 | 333 | 285 | Total Consolidated Companies— International | 3 | 375 | 326 | 314 | 333 | ||||||||||||||||||||||||||||||||
Affiliates3 | Various Locations | 9 | 747 | 653 | 688 | 765 | Various Locations | 8 | 762 | 653 | 653 | 688 | ||||||||||||||||||||||||||||||||
Total Including Affiliates— International | Total Including Affiliates— International | 12 | 1,122 | 967 | 1,021 | 1,050 | Total Including Affiliates— International | 11 | 1,137 | 979 | 967 | 1,021 | ||||||||||||||||||||||||||||||||
Total Including Affiliates —Worldwide | Total Including Affiliates —Worldwide | 18 | 2,139 | 1,858 | 1,833 | 1,989 | Total Including Affiliates— Worldwide | 17 | 2,158 | 1,878 | 1,858 | 1,833 | ||||||||||||||||||||||||||||||||
1 | ||
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 | |
3 |
24
24
2008 | 2007 | 2006 | 2009 | 2008 | 2007 | |||||||||||||||||||
United States | ||||||||||||||||||||||||
Gasolines | 692 | 728 | 712 | 720 | 692 | 728 | ||||||||||||||||||
Jet Fuel | 274 | 271 | 280 | 254 | 274 | 271 | ||||||||||||||||||
Gas Oils and Kerosene | 229 | 221 | 252 | 226 | 229 | 221 | ||||||||||||||||||
Residual Fuel Oil | 127 | 138 | 128 | 110 | 127 | 138 | ||||||||||||||||||
Other Petroleum Products2 | 91 | 99 | 122 | |||||||||||||||||||||
Other Petroleum Products1 | 93 | 91 | 99 | |||||||||||||||||||||
Total United States | 1,413 | 1,457 | 1,494 | 1,403 | 1,413 | 1,457 | ||||||||||||||||||
International3 | ||||||||||||||||||||||||
International2 | ||||||||||||||||||||||||
Gasolines | 589 | 581 | 595 | 555 | 589 | 581 | ||||||||||||||||||
Jet Fuel | 278 | 274 | 266 | 264 | 278 | 274 | ||||||||||||||||||
Gas Oils and Kerosene | 710 | 730 | 776 | 647 | 710 | 730 | ||||||||||||||||||
Residual Fuel Oil | 257 | 271 | 324 | 209 | 257 | 271 | ||||||||||||||||||
Other Petroleum Products2 | 182 | 171 | 166 | |||||||||||||||||||||
Other Petroleum Products1 | 176 | 182 | 171 | |||||||||||||||||||||
Total International | 2,016 | 2,027 | 2,127 | 1,851 | 2,016 | 2,027 | ||||||||||||||||||
Total Worldwide3 | 3,429 | 3,484 | 3,621 | |||||||||||||||||||||
Total Worldwide2 | 3,254 | 3,429 | 3,484 | |||||||||||||||||||||
1 | Includes buy/sell arrangements. Refer to Note 14 on page FS-43. | — | — | 50 | Principally naphtha, lubricants, asphalt and coke. | |||||||||||||||||||||||
2 | Principally naphtha, lubricants, asphalt and coke. | Includes share of equity affiliates’ sales: | 516 | 512 | 492 | |||||||||||||||||||||||
3 | Includes share of equity affiliates’ sales: | 512 | 492 | 492 |
25
25
Net Mileage | ||||
United States: | ||||
Crude Oil | ||||
Natural Gas | ||||
Petroleum Products3 | ||||
Total United States | ||||
International: | ||||
Crude Oil | 700 | |||
Natural Gas | ||||
Petroleum Products3 | ||||
Total International | ||||
Worldwide | ||||
1 | Partially owned pipelines are included at the company’s equity | |
2 | ||
3 | Includes |
26
26
U.S. Flag | Foreign Flag | U.S. Flag | Foreign Flag | |||||||||||||||||||||||||||||
Cargo Capacity | Cargo Capacity | Cargo Capacity | Cargo Capacity | |||||||||||||||||||||||||||||
Number | (Millions of Barrels) | Number | (Millions of Barrels) | Number | (Millions of Barrels) | Number | (Millions of Barrels) | |||||||||||||||||||||||||
Owned | 3 | 0.8 | 1 | 1.1 | 3 | 0.8 | 1 | 1.1 | ||||||||||||||||||||||||
Bareboat Chartered | 2 | 0.7 | 18 | 27.1 | ||||||||||||||||||||||||||||
Time Chartered* | — | — | 17 | 14.6 | ||||||||||||||||||||||||||||
Bareboat-Chartered | 2 | 0.7 | 18 | 27.1 | ||||||||||||||||||||||||||||
Time-Chartered2 | — | — | 17 | 12.4 | ||||||||||||||||||||||||||||
Total | 5 | 1.5 | 36 | 42.8 | 5 | 1.5 | 36 | 40.6 |
2 | Tankers chartered for more than one year. |
27
27
28
28
29
29
Item 1A. | Risk Factors |
30
30
31
Item 1B. | Unresolved Staff Comments |
Item 2. | Properties |
Item 3. | Legal Proceedings |
32
31
Item 4. | Submission of Matters to a Vote of Security Holders |
3233
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 | ) | |||||||||||
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(2) | ||||||||||||
Oct. 1 – Oct. 31, 2009 | 516 | 75.79 | — | — | ||||||||||||
Nov. 1 – Nov. 30, 2009 | 2,380 | 78.59 | — | — | ||||||||||||
Dec. 1 – Dec. 31, 2009 | — | — | — | — | ||||||||||||
Total Oct. 1 – Dec. 31, 2009 | 2,896 | 78.09 | — | — | ||||||||||||
(1) | Pertains to common shares repurchased during the three-month period ended December 31, | |
(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 |
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 |
3334
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 |
3435
Item 10. | Directors, Executive Officers and Corporate Governance |
Name and Age | Current and Prior Positions (up to five years) | Current Areas of Responsibility | ||||
Chairman of the Board and Chief Executive Officer (since | Chief Executive Officer | |||||
Vice Chairman of the Board Executive Vice President (2008 to 2009) | ||||||
Vice President and International Exploration and Production Company (2005 through 2007) | ||||||
G.L. Kirkland | 59 | Vice Chairman of the Board and Executive Vice President (since 2010) | Worldwide Exploration and Production Activities and Global | |||
Executive Vice President (2005 through 2009) | Gas Activities, including Natural Gas Trading | |||||
J.E. Bethancourt | Executive Vice President (since 2003) | Technology; Environment and Resources Company; Procurement | ||||
Executive Vice President (since | ||||||
Vice President and | ||||||
M.K. Wirth | Executive Vice President (since 2006) President of Global Supply and Trading (2004 | Global Refining, Marketing, Lubricants, and Supply and Trading, excluding Natural Gas | ||||
P.E. Yarrington | Vice President and Chief Financial Officer | Finance | ||||
Vice President and Treasurer (2007 through 2008) Vice President, Policy, Government and Public Affairs (2002 to 2007) | ||||||
R.H. Pate | 47 | Vice President and General Counsel (since 2009) Partner and Head of Global Competition Practice | Law |
35
36
Item 11. | Executive Compensation |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Item 14. | Principal Accounting Fees and Services |
3637
Item 15. | Exhibits, Financial Statement Schedules |
Page(s) | ||
FS-26 | ||
FS-27 | ||
FS-28 | ||
FS-29 | ||
FS-30 | ||
FS-31 | ||
FS-32 to |
Year Ended December 31 | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Employee Termination Benefits: | ||||||||||||
Balance at January 1 | $ | 44 | $ | 117 | $ | 28 | ||||||
(Deductions from) additions to expense | (12 | ) | (13 | ) | 106 | |||||||
Payments | (19 | ) | (60 | ) | (17 | ) | ||||||
Balance at December 31 | $ | 13 | $ | 44 | $ | 117 | ||||||
Allowance for Doubtful Accounts: | ||||||||||||
Balance at January 1 | $ | 275 | $ | 200 | $ | 217 | ||||||
Additions to expense | 92 | 105 | 29 | |||||||||
Bad debt write-offs | (74 | ) | (30 | ) | (46 | ) | ||||||
Balance at December 31 | $ | 293 | $ | 275 | $ | 200 | ||||||
Deferred Income Tax Valuation Allowance:* | ||||||||||||
Balance at January 1 | $ | 7,535 | $ | 5,949 | $ | 4,391 | ||||||
Additions to deferred income tax expense | 2,204 | 2,599 | 1,894 | |||||||||
Reduction of deferred income tax expense | (1,818 | ) | (1,013 | ) | (336 | ) | ||||||
Balance at December 31 | $ | 7,921 | $ | 7,535 | $ | 5,949 | ||||||
* |
The Exhibit Index on pagesE-1 andE-2 lists the exhibits that are filed as part of this report. |
37
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 | ||||||
38
By | /s/ |
Principal Executive Officers | ||
(and Directors) | Directors | |
/s/ Board and Chief Executive Officer | Samuel H. Armacost* Samuel H. Armacost | |
/s/ | 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 | Enrique Hernandez, Jr.* Enrique Hernandez, Jr. Franklyn G. Jenifer* Franklyn G. Jenifer Sam Nunn* Sam Nunn | |
Donald B. Rice* Donald B. Rice | ||
Kevin W. Sharer* Kevin W. Sharer | ||
*By: /s/Lydia I. Beebe Lydia I. Beebe, Attorney-in-Fact | ||
Charles R. Shoemate* Charles R. Shoemate | ||
Ronald D. Sugar* Ronald D. Sugar | ||
Carl Ware* Carl Ware |
39
FS-1FS-2FS-2FS-2FS-5FS-6FS-8FS-10FS-10FS-12FS-12FS-13FS-15FS-15FS-17FS-18FS-21FS-24FS-25Consolidated Financial StatementsFS-25FS-26FS-27FS-28FS-29FS-30FS-31FS-32 Notes to the Consolidated Financial Statements Note 1 FS-32Note 2 Note 3 Note 4 FS-34Note 3 FS-35Note 4FS-35Note 5 FS-36Note 6 FS-36Note 7 FS-36Note 8 FS-37Note 9 Note 10 Note 11 FS-38Note 10 FS-40Note 11FS-41Note 12 FS-41Note 13 FS-43Note 14 FS-43Note 15 FS-44Note 16 FS-45Note 17 FS-47Note 18 FS-47Note 19 FS-48Note 20 FS-48Note 2120 FS-49Note 22FS-51Note 23FS-56Note 24FS-58Note 25FS-59Note 26FS-59Note 27FS-59 Five-Year Financial SummaryNote 21 FS-61Supplemental Information on Oil and Gas Producing ActivitiesFS-62FS-1
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 % Millions of dollars, except per-share amounts 2009 2008 2007 Net Income Attributable to
Chevron Corporation $ 10,483 $ 23,931 $ 18,688 Per Share Amounts: Net Income Attributable to
Chevron Corporation – Basic $ 5.26 $ 11.74 $ 8.83 – Diluted $ 5.24 $ 11.67 $ 8.77 Dividends $ 2.66 $ 2.53 $ 2.26 Sales and Other
Operating Revenues $ 167,402 $ 264,958 $ 214,091 Return on: Capital Employed 10.6 % 26.6 % 23.1 % Stockholders’ Equity 11.7 % 29.2 % 25.6 % Income Millions of dollars 2008 2007 2006 2009 2008 2007 Upstream – Exploration and Production Upstream – Exploration and Production United States $ 7,126 $ 4,532 $ 4,270 $ 2,216 $ 7,126 $ 4,532 International 14,584 10,284 8,872 8,215 14,584 10,284 Total Upstream 21,710 14,816 13,142 10,431 21,710 14,816 Downstream – Refining, Marketing and Transportation United States 1,369 966 1,938 (273 ) 1,369 966 International 2,060 2,536 2,035 838 2,060 2,536 Total Downstream 3,429 3,502 3,973 565 3,429 3,502 Chemicals 182 396 539 409 182 396 All Other (1,390 ) (26 ) (516 ) (922 ) (1,390 ) (26 ) Net Income* $ 23,931 $ 18,688 $ 17,138
Chevron Corporation(1),(2) $ 10,483 $ 23,931 $ 18,688 *Includes Foreign Currency Effects: $ 862 $(352 ) $(219 ) $ (744 ) $ 862 $ (352 ) (2) Also referred to as “earnings” in the discussions that follow. endingended December 31, 2008.2009.
France, India, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, the Philippines, Qatar, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela and Vietnam.
ments.investments. 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
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
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-3
The company estimates that oil-equivalent production in 20092010 will average approximately 2.632.73 million barrels per day. This estimate is subject to many factors and uncertainties, including additional quotas that may be imposed by OPEC, price effects on production volumes calculated under cost-recovery andvariable-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
FS-4
the crude-oil and product-supply functions and the economic returns on invested capital.functions. 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 oilcrude-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.
FS-4
AustraliaAngola Started production from Train 5 of the 17 percent-owned North West Shelf Venture onshore liquefied-natural-gas (LNG) facility in West Australia, increasing export capacity from about 12 million metric tons annually to more than 16 million. The company also announced plans for an LNG project that initially will have a capacity of 5 million tons per year and process natural gas from Chevron’s 100 percent-owned Wheatstone discovery located on the northwest coast of mainland Australia.Canada Finalized agreements with the government of Newfoundland and Labrador to develop the 27 percent-owned Hebron heavy-oil project off the eastern coast.
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.
operated facilities will have LNG processing capacity of 8.6 million metric tons per year and a co-located domestic natural-gas plant. The facilities will support development of Chevron’s interests in the Wheatstone Field and nearby Iago Field. Agreements were signed with two companies to join the Wheatstone Project as combined 25 percent owners and suppliers of natural gas for the project’s first two LNG trains. In addition, nonbinding HOAs were signed with two Asian customers to take delivery of 4.9 million metric tons per year of LNG from the project (about 60 percent of the total LNG available from the foundation project) and to acquire a 16.8 percent equity interest in the Wheatstone Field licenses and a 12.6 percent interest in the foundation natural gas processing facilities at the final investment decision. In May 2009 the company announced the successful |
FS-5
Downstream
FS-5
Other
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Income | $ | 7,126 | $ | 4,532 | $ | 4,270 | ||||||||||||||||||||
Earnings | $ | 2,216 | $ | 7,126 | $ | 4,532 | ||||||||||||||||||||
FS-6
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 | ) |
Millions of dollars | 2009 | 2008 | 2007 | ||||||||||
Earnings* | $ | 8,215 | $ | 14,584 | $ | 10,284 | |||||||
*Includes foreign currency effects: | $ (571 | ) | $ 873 | $ (417 | ) |
FS-6
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.
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Income | $ | 1,369 | $ | 966 | $ | 1,938 | ||||||||||||||||||||
Earnings | $ | (273 | ) | $ | 1,369 | $ | 966 | |||||||||||||||||||
FS-7
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income* | $ | 2,060 | $ | 2,536 | $ | 2,035 | |||||||
*Includes Foreign Currency Effects: | $ 193 | $ 62 | $ 98 |
Millions of dollars | 2009 | 2008 | 2007 | ||||||||||
Earnings* | $ | 838 | $ | 2,060 | $ | 2,536 | |||||||
*Includes foreign currency effects: | $ (213 | ) | $ 193 | $ 62 |
of gains recorded in 2008 on commodity derivative instruments. Foreign-currency effects produced a negative variance of $400 million. Partially offsetting these items was a $1.0 billion benefit from lower operating expenses associated mainly with contract labor, professional services and transportation costs and about a $550 million increase in gains on asset sales primarily in certain countries in Latin America and Africa. Earnings in 2008 of $2.1 billion decreased nearly $500 million from 2007. Earnings in 2007 included gains of approximately $1 billion on the sale of assets, which included marketing assets in the Benelux region of Europe and an interest in a refinery. The $500 million other improvement 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 from sales of |
FS-7
lower demand. 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.level with 2007.
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Income* | $ | 182 | $ | 396 | $ | 539 | |||||||
*Includes Foreign Currency Effects: | $ (18 | ) | $ (3 | ) | $ (8 | ) |
Millions of dollars | 2009 | 2008 | 2007 | ||||||||||
Earnings* | $ | 409 | $ | 182 | $ | 396 | |||||||
*Includes foreign currency effects: | $ 15 | $ (18 | ) | $ (3 | ) |
and 2007, respectively. For CPChem, the earnings improvement from 2008 to 2009 reflected lower utility and manufacturing costs as well as the absence of an impairment recorded in 2008. These benefits were partially offset by lower margins on the sale of commodity chemicals. For Oronite, earnings increased in 2009 due to higher margins on sales of lubricant and fuel additives, the effect of which more than offset the impact of lower sales volumes. In 2008, segment earnings were $182 million, compared with $396 million in 2007. 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 Oronite due to lower volumes and higher operating expenses. |
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Net Charges* | $ | (1,390 | ) | $ | (26 | ) | $ | (516 | ) | $ | (922 | ) | $ | (1,390 | ) | $ | (26 | ) | ||||||||
*Includes Foreign Currency Effects: | $ (186 | ) | $ 6 | $ 62 | ||||||||||||||||||||||
*Includes foreign currency effects: | $ 25 | $ (186 | ) | $ 6 |
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, Inc. prior to its sale in May 2007.
FS-8
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Sales and other operating revenues | $ | 264,958 | $ | 214,091 | $ | 204,892 | $ | 167,402 | $ | 264,958 | $ | 214,091 | ||||||||||||||
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Income from equity affiliates | $ | 5,366 | $ | 4,144 | $ | 4,255 | $ | 3,316 | $ | 5,366 | $ | 4,144 | ||||||||||||||
FS-8
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Other income | $ | 2,681 | $ | 2,669 | $ | 971 | $ | 918 | $ | 2,681 | $ | 2,669 | ||||||||||||||
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Purchased crude oil and products | $ | 171,397 | $ | 133,309 | $ | 128,151 | $ | 99,653 | $ | 171,397 | $ | 133,309 | ||||||||||||||
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Operating, selling, general and administrative expenses | $ | 26,551 | $ | 22,858 | $ | 19,717 | $ | 22,384 | $ | 26,551 | $ | 22,858 | ||||||||||||||
Millions of dollars | 2009 | 2008 | 2007 | ||||||||||
Exploration expense | $ | 1,342 | $ | 1,169 | $ | 1,323 | |||||||
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Exploration expense | $ | 1,169 | $ | 1,323 | $ | 1,364 | |||||||
Exploration expensesinternational operations. Expenses in 2008 declined from 2007 mainly 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 | 2009 | 2008 | 2007 | ||||||||||
Depreciation, depletion and amortization | $ | 12,110 | $ | 9,528 | $ | 8,708 | |||||||
Millions of dollars | 2008 | 2007 | 2006 | ||||||||||
Depreciation, depletion and amortization | $ | 9,528 | $ | 8,708 | $ | 7,506 | |||||||
Depreciation, depletion and amortization expenses increased in 2009 from 2008 due to incremental production related to start-ups for upstream projects in the United States and Africa and higher depreciation rates for certain other oil and gas producing fields. The increase in 2008 from 2007 was largely due to higher depreciation rates for certain crude oilcrude-oil and natural gasnatural-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 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Taxes other than on income | $ | 21,303 | $ | 22,266 | $ | 20,883 | $ | 17,591 | $ | 21,303 | $ | 22,266 | ||||||||||||||
FS-9
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Interest and debt expense | $ | – | $ | 166 | $ | 451 | $ | 28 | $ | – | $ | 166 | ||||||||||||||
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Income tax expense | $ | 19,026 | $ | 13,479 | $ | 14,838 | $ | 7,965 | $ | 19,026 | $ | 13,479 | ||||||||||||||
2009 | 2008 | 2007 | |||||||||||
U.S. Upstream | |||||||||||||
Net Crude Oil and Natural Gas | |||||||||||||
Liquids Production (MBPD) | 484 | 421 | 460 | ||||||||||
Net Natural Gas Production (MMCFPD)3 | 1,399 | 1,501 | 1,699 | ||||||||||
Net Oil-Equivalent Production (MBOEPD) | 717 | 671 | 743 | ||||||||||
Sales of Natural Gas (MMCFPD) | 5,901 | 7,226 | 7,624 | ||||||||||
Sales of Natural Gas Liquids (MBPD) | 17 | 15 | 25 | ||||||||||
Revenues From Net Production | |||||||||||||
Liquids ($/Bbl) | $ | 54.36 | $ | 88.43 | $ | 63.16 | |||||||
Natural Gas ($/MCF) | $ | 3.73 | $ | 7.90 | $ | 6.12 | |||||||
International Upstream | |||||||||||||
Net Crude Oil and Natural Gas | |||||||||||||
Liquids Production (MBPD) | 1,362 | 1,228 | 1,296 | ||||||||||
Net Natural Gas Production (MMCFPD)3 | 3,590 | 3,624 | 3,320 | ||||||||||
Net Oil-Equivalent | |||||||||||||
Production (MBOEPD)4 | 1,987 | 1,859 | 1,876 | ||||||||||
Sales of Natural Gas (MMCFPD) | 4,062 | 4,215 | 3,792 | ||||||||||
Sales of Natural Gas Liquids (MBPD) | 23 | 17 | 22 | ||||||||||
Revenues From Liftings | |||||||||||||
Liquids ($/Bbl) | $ | 55.97 | $ | 86.51 | $ | 65.01 | |||||||
Natural Gas ($/MCF) | $ | 4.01 | $ | 5.19 | $ | 3.90 | |||||||
Worldwide Upstream | |||||||||||||
Net Oil-Equivalent Production (MBOEPD)3,4 | |||||||||||||
United States | 717 | 671 | 743 | ||||||||||
International | 1,987 | 1,859 | 1,876 | ||||||||||
Total | 2,704 | 2,530 | 2,619 | ||||||||||
U.S. Downstream | |||||||||||||
Gasoline Sales (MBPD)5 | 720 | 692 | 728 | ||||||||||
Other Refined-Product Sales (MBPD) | 683 | 721 | 729 | ||||||||||
Total Refined Product Sales (MBPD) | 1,403 | 1,413 | 1,457 | ||||||||||
Sales of Natural Gas Liquids (MBPD) | 144 | 144 | 135 | ||||||||||
Refinery Input (MBPD) | 899 | 891 | 812 | ||||||||||
International Downstream | |||||||||||||
Gasoline Sales (MBPD)5 | 555 | 589 | 581 | ||||||||||
Other Refined-Product Sales (MBPD) | 1,296 | 1,427 | 1,446 | ||||||||||
Total Refined Product Sales (MBPD)6 | 1,851 | 2,016 | 2,027 | ||||||||||
Sales of Natural Gas Liquids (MBPD) | 88 | 97 | 96 | ||||||||||
Refinery Input (MBPD) | 979 | 967 | 1,021 | ||||||||||
1 | Includes company share of equity 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 natural gas = 1 barrel of oil. | |
3 | Includes natural gas consumed in operations (MMCFPD): |
United States | 58 | 70 | 65 | |||||||||
International | 463 | 450 | 433 | |||||||||
4 Includes production from oil sands, Net (MBPD): | 26 | 27 | 27 | |||||||||
5 Includes branded and unbranded gasoline. | ||||||||||||
6 Includes sales of affiliates (MBPD): | 516 | 512 | 492 |
FS-9FS-10
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 |
FS-10
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, 2008.2009. 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 intends to file a new shelf registration statement when the company’s Board of Directors authorized the issuance ofcurrent one or more series of notes or debentures in an aggregate amount up to $5 billion for a term not to exceed ten years.expires.
FS-11
2009 | 2008 | 2007 | ||||||||||||||||||||||||||||||||||||
Millions of dollars | U.S. | Int’l. | Total | U.S. | Int’l. | Total | U.S. | Int’l. | Total | |||||||||||||||||||||||||||||
Upstream – Exploration and Production | $ | 3,261 | $ | 13,848 | $ | 17,109 | $ | 5,516 | $ | 11,944 | $ | 17,460 | $ | 4,558 | $ | 10,980 | $ | 15,538 | ||||||||||||||||||||
Downstream – Refining, Marketing and Transportation | 1,910 | 2,511 | 4,421 | 2,182 | 2,023 | 4,205 | 1,576 | 1,867 | 3,443 | |||||||||||||||||||||||||||||
Chemicals | 210 | 92 | 302 | 407 | 78 | 485 | 218 | 53 | 271 | |||||||||||||||||||||||||||||
All Other | 402 | 3 | 405 | 618 | 7 | 625 | 768 | 6 | 774 | |||||||||||||||||||||||||||||
Total | $ | 5,783 | $ | 16,454 | $ | 22,237 | $ | 8,723 | $ | 14,052 | $ | 22,775 | $ | 7,120 | $ | 12,906 | $ | 20,026 | ||||||||||||||||||||
Total, Excluding Equity in Affiliates | $ | 5,558 | $ | 15,094 | $ | 20,652 | $ | 8,241 | $ | 12,228 | $ | 20,469 | $ | 6,900 | $ | 10,790 | $ | 17,690 | ||||||||||||||||||||
Capital and exploratory expenditures Total expenditures for 2009 were $22.2 billion, including $1.6 billion for the company’s share of equity-affiliate expenditures and $2 billion for the extension of an upstream concession. In 2008 and 2007, expenditures were $22.8 billion and $20.0 billion, respectively, including the company’s share of affiliates’ expenditures of $2.3 billion in both periods. Of the $22.2 billion of expenditures in 2009, about three-fourths, or $17.1 billion, is related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2008 and 2007. International upstream accounted for about 80 percent of the worldwide upstream investment in 2009 and about 70 percent in 2008 and 2007, |
FS-11
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 20092010 is estimated at $4.3$3.4 billion, with about $2.0$1.6 billion for projects in the
At December 31 | At December 31 | |||||||||||||||||||||||||
2008 | 2007 | 2006 | 2009 | 2008 | 2007 | |||||||||||||||||||||
Current Ratio | 1.1 | 1.2 | 1.3 | 1.4 | 1.1 | 1.2 | ||||||||||||||||||||
Interest Coverage Ratio | 166.9 | 69.2 | 53.5 | 62.3 | 166.9 | 69.2 | ||||||||||||||||||||
Debt Ratio | 9.3 | % | 8.6 | % | 12.5 | % | 10.3 | % | 9.3 | % | 8.6 | % | ||||||||||||||
FS-12
Interest Coverage Ratio– income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. The company’s interest coverage ratio in 2009 was lower than 2008 and 2007 due to lower before-tax income. Debt Ratio– total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity. The increase in 2009 over 2008 and 2007 was primarily due to the increase in debt as a result of the $5 billion issuance of public bonds in 2009. Guarantees, Off-Balance- Sheet Arrangements and |
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
Millions of dollars | Commitment Expiration by Period | Commitment Expiration by Period | ||||||||||||||||||||||||||||||||||||||
2010– | 2012– | After | 2011– | 2013– | After | |||||||||||||||||||||||||||||||||||
Total | 2009 | 2011 | 2013 | 2013 | Total | 2010 | 2012 | 2014 | 2014 | |||||||||||||||||||||||||||||||
Guarantee of non-consolidated affiliate or joint-venture obligation | $ | 613 | $ | – | $ | – | $ | 76 | $ | 537 | ||||||||||||||||||||||||||||||
Guarantee of non- consolidated affiliate or joint-venture obligation | $ | 613 | $ | – | $ | 38 | $ | 77 | $ | 498 |
FS-12
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 AgreementsThe 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$7.5 billion; 2011 – $3.6$4.3 billion; 2012 – $1.5$1.4 billion; 2013 – $1.3$1.4 billion; 2014 – $1.0 billion; 2015 and after – $4.3$4.1 billion. A portion of these commitments may ultimately be shared with project
FS-13
Millions of dollars | Payments Due by Period | Payments Due by Period | ||||||||||||||||||||||||||||||||||||||
2010– | 2012– | After | 2011– | 2013– | After | |||||||||||||||||||||||||||||||||||
Total | 2009 | 2011 | 2013 | 2013 | Total | 2010 | 2012 | 2014 | 2014 | |||||||||||||||||||||||||||||||
On Balance Sheet:2 | ||||||||||||||||||||||||||||||||||||||||
Short-Term Debt3 | $ | 2,818 | $ | 2,818 | $ | – | $ | – | $ | – | $ | 384 | $ | 384 | $ | – | $ | – | $ | – | ||||||||||||||||||||
Long-Term Debt3 | 5,742 | – | 5,061 | 74 | 607 | 9,829 | – | 5,743 | 2,041 | 2,045 | ||||||||||||||||||||||||||||||
Noncancelable Capital Lease Obligations | 548 | 97 | 154 | 143 | 154 | 499 | 90 | 168 | 104 | 137 | ||||||||||||||||||||||||||||||
Interest | 2,133 | 174 | 322 | 312 | 1,325 | 2,590 | 317 | 566 | 426 | 1,281 | ||||||||||||||||||||||||||||||
Off-Balance-Sheet: | ||||||||||||||||||||||||||||||||||||||||
Noncancelable Operating Lease Obligations | 2,888 | 503 | 835 | 603 | 947 | 3,364 | 568 | 844 | 719 | 1,233 | ||||||||||||||||||||||||||||||
Throughput and Take-or-Pay Agreements | 15,726 | 5,063 | 5,383 | 1,261 | 4,019 | 15,130 | 6,555 | 3,825 | 819 | 3,931 | ||||||||||||||||||||||||||||||
Other Unconditional Purchase Obligations4 | 5,356 | 1,342 | 2,159 | 1,541 | 314 | 4,617 | 1,024 | 1,906 | 1,538 | 149 | ||||||||||||||||||||||||||||||
1 | Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note | |
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 | $ | |
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 |
FS-13
Factors” in Part I, Item 1A, of the company’s 20082009 Annual Report on Form 10-K.
FS-14
Millions of dollars | 2008 | 2007 | 2009 | 2008 | ||||||||||||||
Crude Oil | $ | 39 | $ | 29 | $ | 17 | $ | 39 | ||||||||||
Natural Gas | 5 | 3 | 4 | 5 | ||||||||||||||
Refined Products | 45 | 23 | 19 | 45 | ||||||||||||||
FS-14
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.
FS-15
FS-15
estimate a reasonablereasonably possible loss (or a range of loss).
Millions of dollars | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | ||||||||||||||||||||
Balance at January 1 | $ | 1,539 | $ | 1,441 | $ | 1,469 | $ | 1,818 | $ | 1,539 | $ | 1,441 | ||||||||||||||
Net Additions | 784 | 562 | 366 | 351 | 784 | 562 | ||||||||||||||||||||
Expenditures | (505 | ) | (464 | ) | (394 | ) | (469 | ) | (505 | ) | (464 | ) | ||||||||||||||
Balance at December 31 | $ | 1,818 | $ | 1,539 | $ | 1,441 | $ | 1,700 | $ | 1,818 | $ | 1,539 | ||||||||||||||
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 20082009 was $120$185 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 results of operations, consolidated financial position or liquidity.
FS-16
FS-16
reasonably estimated. The liability balance of approximately $9.4$10.2 billion for asset retirement obligations at year-end 20082009 related primarily to upstream properties.
that could be classified as proved. The effect on exploration expenses in future periods of the $2.1$2.4 billion of suspended wells at year-end 20082009 is uncertain pending future activities, including normal project evaluation and additional drilling.
FS-17
FS-17
sideredconsidered acceptable at the time but now require investigative or remedial work or both to meet current standards.
1. | the nature of the estimates |
2. | the impact of the estimates and assumptions on the company’s financial condition or operating performance is material. |
FS-18
FS-18
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.
FS-19
FS-19
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.
FS-20
FS-20
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.
efitsbenefits 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 1615 beginning on page FS-45.FS-46. 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, 2008.2009.
FS-21
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 representationsuperseded existing literature of the location and fair value amountsFASB, Emerging Issues Task Force, American Institute 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 earningsCPAs and other comprehensive income.sources. The ASC did not change GAAP, but organized the literature into about 90 accounting Topics. Adoption of the ASC did not affect the company’s accounting.
FS-21
FS-22
FS-23
Unaudited
2008 | 2007 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Millions of dollars, except per-share amounts | 4th Q | 3rd Q | 2nd Q | 1st Q | 4th Q | 3rd Q | 2nd Q | 1st Q | 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 | $ | 47,588 | $ | 45,180 | $ | 39,647 | $ | 34,987 | $ | 43,145 | $ | 76,192 | $ | 80,962 | $ | 64,659 | ||||||||||||||||||||||||||||||||||
Income from equity affiliates | 886 | 1,673 | 1,563 | 1,244 | 1,153 | 1,160 | 894 | 937 | 898 | 1,072 | 735 | 611 | 886 | 1,673 | 1,563 | 1,244 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Other income | 1,172 | 1,002 | 464 | 43 | 357 | 468 | 856 | 988 | 190 | 373 | (177 | ) | 532 | 1,172 | 1,002 | 464 | 43 | |||||||||||||||||||||||||||||||||||||||||||||||||
Total Revenues and Other Income | 45,203 | 78,867 | 82,989 | 65,946 | 61,410 | 55,173 | 56,094 | 48,227 | 48,676 | 46,625 | 40,205 | 36,130 | 45,203 | 78,867 | 82,989 | 65,946 | ||||||||||||||||||||||||||||||||||||||||||||||||||
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 | 28,606 | 26,969 | 23,678 | 20,400 | 23,575 | 49,238 | 56,056 | 42,528 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Operating expenses | 5,416 | 5,676 | 5,248 | 4,455 | 4,798 | 4,397 | 4,124 | 3,613 | 4,899 | 4,403 | 4,209 | 4,346 | 5,416 | 5,676 | 5,248 | 4,455 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Selling, general and administrative expenses | 1,492 | 1,278 | 1,639 | 1,347 | 1,833 | 1,446 | 1,516 | 1,131 | 1,330 | 1,177 | 1,043 | 977 | 1,492 | 1,278 | 1,639 | 1,347 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Exploration expenses | 338 | 271 | 307 | 253 | 449 | 295 | 273 | 306 | 281 | 242 | 438 | 381 | 338 | 271 | 307 | 253 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 2,589 | 2,449 | 2,275 | 2,215 | 2,094 | 2,495 | 2,156 | 1,963 | 3,156 | 2,988 | 3,099 | 2,867 | 2,589 | 2,449 | 2,275 | 2,215 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Taxes other than on income1 | 4,547 | 5,614 | 5,699 | 5,443 | 5,560 | 5,538 | 5,743 | 5,425 | 4,583 | 4,644 | 4,386 | 3,978 | 4,547 | 5,614 | 5,699 | 5,443 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Interest and debt expense | – | – | – | – | 7 | 22 | 63 | 74 | – | 14 | 6 | 8 | – | – | – | – | ||||||||||||||||||||||||||||||||||||||||||||||||||
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 | 42,855 | 40,437 | 36,859 | 32,957 | 37,957 | 64,526 | 71,224 | 56,241 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Income Before Income Tax Expense | 7,240 | 14,309 | 11,731 | 9,677 | 8,578 | 6,967 | 9,062 | 7,560 | 5,821 | 6,188 | 3,346 | 3,173 | 7,246 | 14,341 | 11,765 | 9,705 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Expense | 2,345 | 6,416 | 5,756 | 4,509 | 3,703 | 3,249 | 3,682 | 2,845 | 2,719 | 2,342 | 1,585 | 1,319 | 2,345 | 6,416 | 5,756 | 4,509 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income | $ | 4,895 | $ | 7,893 | $ | 5,975 | $ | 5,168 | $ | 4,875 | $ | 3,718 | $ | 5,380 | $ | 4,715 | $ | 3,102 | $ | 3,846 | $ | 1,761 | $ | 1,854 | $ | 4,901 | $ | 7,925 | $ | 6,009 | $ | 5,196 | ||||||||||||||||||||||||||||||||||
Less: Net income attributable to noncontrolling interests | 32 | 15 | 16 | 17 | 6 | 32 | 34 | 28 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income Attributable to Chevron Corporation | $ | 3,070 | $ | 3,831 | $ | 1,745 | $ | 1,837 | $ | 4,895 | $ | 7,893 | $ | 5,975 | $ | 5,168 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Per-Share of Common Stock | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income Attributable to Chevron Corporation | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
– Basic | $ | 2.45 | $ | 3.88 | $ | 2.91 | $ | 2.50 | $ | 2.34 | $ | 1.77 | $ | 2.52 | $ | 2.20 | $ | 1.54 | $ | 1.92 | $ | 0.88 | $ | 0.92 | $ | 2.45 | $ | 3.88 | $ | 2.91 | $ | 2.50 | ||||||||||||||||||||||||||||||||||
– Diluted | $ | 2.44 | $ | 3.85 | $ | 2.90 | $ | 2.48 | $ | 2.32 | $ | 1.75 | $ | 2.52 | $ | 2.18 | $ | 1.53 | $ | 1.92 | $ | 0.87 | $ | 0.92 | $ | 2.44 | $ | 3.85 | $ | 2.90 | $ | 2.48 | ||||||||||||||||||||||||||||||||||
Dividends | $ | 0.65 | $ | 0.65 | $ | 0.65 | $ | 0.58 | $ | 0.58 | $ | 0.58 | $ | 0.58 | $ | 0.52 | $ | 0.68 | $ | 0.68 | $ | 0.65 | $ | 0.65 | $ | 0.65 | $ | 0.65 | $ | 0.65 | $ | 0.58 | ||||||||||||||||||||||||||||||||||
Common Stock Price Range – High2 | $ | 82.20 | $ | 99.08 | $ | 103.09 | $ | 94.61 | $ | 94.86 | $ | 94.84 | $ | 84.24 | $ | 74.95 | $ | 79.64 | $ | 72.64 | $ | 72.67 | $ | 77.35 | $ | 82.20 | $ | 99.08 | $ | 103.09 | $ | 94.61 | ||||||||||||||||||||||||||||||||||
– Low2 | $ | 57.83 | $ | 77.50 | $ | 86.74 | $ | 77.51 | $ | 83.79 | $ | 80.76 | $ | 74.83 | $ | 66.43 | $ | 68.14 | $ | 61.40 | $ | 63.75 | $ | 56.46 | $ | 57.83 | $ | 77.50 | $ | 86.74 | $ | 77.51 | ||||||||||||||||||||||||||||||||||
1 Includes excise, value-added and similar taxes: | $ | 2,080 | $ | 2,577 | $ | 2,652 | $ | 2,537 | $ | 2,548 | $ | 2,550 | $ | 2,609 | $ | 2,414 | $ | 2,086 | $ | 2,079 | $ | 2,034 | $ | 1,910 | $ | 2,080 | $ | 2,577 | $ | 2,652 | $ | 2,537 | ||||||||||||||||||||||||||||||||||
2 End of day price. |
FS-24
Patricia E. Yarrington | Mark A. Humphrey | |||
Chairman of the Board | Vice President | Vice President | ||
and Chief Executive Officer | and Chief Financial Officer | and Comptroller |
FS-25
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.
FS-26
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
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
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
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
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 | |||||||||||||||||||
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
Revenues and Other Income | |||||||||||||
Sales and other operating revenues* | $ | 167,402 | $ | 264,958 | $ | 214,091 | |||||||
Income from equity affiliates | 3,316 | 5,366 | 4,144 | ||||||||||
Other income | 918 | 2,681 | 2,669 | ||||||||||
Total Revenues and Other Income | 171,636 | 273,005 | 220,904 | ||||||||||
Costs and Other Deductions | |||||||||||||
Purchased crude oil and products | 99,653 | 171,397 | 133,309 | ||||||||||
Operating expenses | 17,857 | 20,795 | 16,932 | ||||||||||
Selling, general and administrative expenses | 4,527 | 5,756 | 5,926 | ||||||||||
Exploration expenses | 1,342 | 1,169 | 1,323 | ||||||||||
Depreciation, depletion and amortization | 12,110 | 9,528 | 8,708 | ||||||||||
Taxes other than on income* | 17,591 | 21,303 | 22,266 | ||||||||||
Interest and debt expense | 28 | – | 166 | ||||||||||
Total Costs and Other Deductions | 153,108 | 229,948 | 188,630 | ||||||||||
Income Before Income Tax Expense | 18,528 | 43,057 | 32,274 | ||||||||||
Income Tax Expense | 7,965 | 19,026 | 13,479 | ||||||||||
Net Income | 10,563 | 24,031 | 18,795 | ||||||||||
Less: Net income attributable to noncontrolling interests | 80 | 100 | 107 | ||||||||||
Net Income Attributable to Chevron Corporation | $ | 10,483 | $ | 23,931 | $ | 18,688 | |||||||
Per-Share of Common Stock | |||||||||||||
Net Income Attributable to Chevron Corporation | |||||||||||||
– Basic | $ | 5.26 | $ | 11.74 | $ | 8.83 | |||||||
– Diluted | $ | 5.24 | $ | 11.67 | $ | 8.77 | |||||||
*Includes excise, value-added and similar taxes. | $ | 8,109 | $ | 9,846 | $ | 10,121 |
FS-31FS-27
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
Net Income | $ | 10,563 | $ | 24,031 | $ | 18,795 | |||||||
Currency translation adjustment | |||||||||||||
Unrealized net change arising during period | 60 | (112 | ) | 31 | |||||||||
Unrealized holding gain (loss) on securities | |||||||||||||
Net gain (loss) arising during period | 2 | (6 | ) | 17 | |||||||||
Reclassification to net income of net realized loss | – | – | 2 | ||||||||||
Total | 2 | (6 | ) | 19 | |||||||||
Derivatives | |||||||||||||
Net derivatives (loss) gain on hedge transactions | (69 | ) | 139 | (10 | ) | ||||||||
Reclassification to net income of net realized (gain) loss | (23 | ) | 32 | 7 | |||||||||
Income taxes on derivatives transactions | 32 | (61 | ) | (3 | ) | ||||||||
Total | (60 | ) | 110 | (6 | ) | ||||||||
Defined benefit plans | |||||||||||||
Actuarial loss | |||||||||||||
Amortization to net income of net actuarial loss | 575 | 483 | 356 | ||||||||||
Actuarial (loss) gain arising during period | (1,099 | ) | (3,228 | ) | 530 | ||||||||
Prior service cost | |||||||||||||
Amortization to net income of net prior service credits | (65 | ) | (64 | ) | (15 | ) | |||||||
Prior service (cost) credit arising during period | (34 | ) | (32 | ) | 204 | ||||||||
Defined benefit plans sponsored by equity affiliates | 65 | (97 | ) | 19 | |||||||||
Income taxes on defined benefit plans | 159 | 1,037 | (409 | ) | |||||||||
Total | (399 | ) | (1,901 | ) | 685 | ||||||||
Other Comprehensive (Loss) Gain, Net of Tax | (397 | ) | (1,909 | ) | 729 | ||||||||
Comprehensive Income | 10,166 | 22,122 | 19,524 | ||||||||||
Comprehensive income attributable to noncontrolling interests | (80 | ) | (100 | ) | (107 | ) | |||||||
Comprehensive Income Attributable to Chevron Corporation | $ | 10,086 | $ | 22,022 | $ | 19,417 | |||||||
FS-28
At December 31 | |||||||||
2009 | 2008 | ||||||||
Assets | |||||||||
Cash and cash equivalents | $ | 8,716 | $ | 9,347 | |||||
Marketable securities | 106 | 213 | |||||||
Accounts and notes receivable (less allowance: 2009 – $228; 2008 – $246) | 17,703 | 15,856 | |||||||
Inventories: | |||||||||
Crude oil and petroleum products | 3,680 | 5,175 | |||||||
Chemicals | 383 | 459 | |||||||
Materials, supplies and other | 1,466 | 1,220 | |||||||
Total inventories | 5,529 | 6,854 | |||||||
Prepaid expenses and other current assets | 5,162 | 4,200 | |||||||
Total Current Assets | 37,216 | 36,470 | |||||||
Long-term receivables, net | 2,282 | 2,413 | |||||||
Investments and advances | 21,158 | 20,920 | |||||||
Properties, plant and equipment, at cost | 188,288 | 173,299 | |||||||
Less: Accumulated depreciation, depletion and amortization | 91,820 | 81,519 | |||||||
Properties, plant and equipment, net | 96,468 | 91,780 | |||||||
Deferred charges and other assets | 2,879 | 4,711 | |||||||
Goodwill | 4,618 | 4,619 | |||||||
Assets held for sale | – | 252 | |||||||
Total Assets | $ | 164,621 | $ | 161,165 | |||||
Liabilities and Equity | |||||||||
Short-term debt | $ | 384 | $ | 2,818 | |||||
Accounts payable | 16,437 | 16,580 | |||||||
Accrued liabilities | 5,375 | 8,077 | |||||||
Federal and other taxes on income | 2,624 | 3,079 | |||||||
Other taxes payable | 1,391 | 1,469 | |||||||
Total Current Liabilities | 26,211 | 32,023 | |||||||
Long-term debt | 9,829 | 5,742 | |||||||
Capital lease obligations | 301 | 341 | |||||||
Deferred credits and other noncurrent obligations | 17,390 | 17,678 | |||||||
Noncurrent deferred income taxes | 11,521 | 11,539 | |||||||
Reserves for employee benefit plans | 6,808 | 6,725 | |||||||
Total Liabilities | 72,060 | 74,048 | |||||||
Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued) | – | – | |||||||
Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares issued at December 31, 2009 and 2008) | 1,832 | 1,832 | |||||||
Capital in excess of par value | 14,631 | 14,448 | |||||||
Retained earnings | 106,289 | 101,102 | |||||||
Accumulated other comprehensive loss | (4,321 | ) | (3,924 | ) | |||||
Deferred compensation and benefit plan trust | (349 | ) | (434 | ) | |||||
Treasury stock, at cost (2009 – 434,954,774 shares; 2008 – 438,444,795 shares) | (26,168 | ) | (26,376 | ) | |||||
Total Chevron Corporation Stockholders’ Equity | 91,914 | 86,648 | |||||||
Noncontrolling interests | 647 | 469 | |||||||
Total Equity | 92,561 | 87,117 | |||||||
Total Liabilities and Equity | $ | 164,621 | $ | 161,165 | |||||
FS-29
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
Operating Activities | |||||||||||||
Net Income | $ | 10,563 | $ | 24,031 | $ | 18,795 | |||||||
Adjustments | |||||||||||||
Depreciation, depletion and amortization | 12,110 | 9,528 | 8,708 | ||||||||||
Dry hole expense | 552 | 375 | 507 | ||||||||||
Distributions less than income from equity affiliates | (103 | ) | (440 | ) | (1,439 | ) | |||||||
Net before-tax gains on asset retirements and sales | (1,255 | ) | (1,358 | ) | (2,315 | ) | |||||||
Net foreign currency effects | 466 | (355 | ) | 378 | |||||||||
Deferred income tax provision | 467 | 598 | 261 | ||||||||||
Net (increase) decrease in operating working capital | (2,301 | ) | (1,673 | ) | 685 | ||||||||
Increase in long-term receivables | (258 | ) | (161 | ) | (82 | ) | |||||||
Decrease (increase) in other deferred charges | 201 | (84 | ) | (530 | ) | ||||||||
Cash contributions to employee pension plans | (1,739 | ) | (839 | ) | (317 | ) | |||||||
Other | 670 | 10 | 326 | ||||||||||
Net Cash Provided by Operating Activities | 19,373 | 29,632 | 24,977 | ||||||||||
Investing Activities | |||||||||||||
Capital expenditures | (19,843 | ) | (19,666 | ) | (16,678 | ) | |||||||
Proceeds and deposits related to asset sales | 2,564 | 1,491 | 3,338 | ||||||||||
Net sales of marketable securities | 127 | 483 | 185 | ||||||||||
Repayment of loans by equity affiliates | 336 | 179 | 21 | ||||||||||
Net sales (purchases) of other short-term investments | 244 | 432 | (799 | ) | |||||||||
Net Cash Used for Investing Activities | (16,572 | ) | (17,081 | ) | (13,933 | ) | |||||||
Financing Activities | |||||||||||||
Net (payments) borrowings of short-term obligations | (3,192 | ) | 2,647 | (345 | ) | ||||||||
Proceeds from issuances of long-term debt | 5,347 | – | 650 | ||||||||||
Repayments of long-term debt and other financing obligations | (496 | ) | (965 | ) | (3,343 | ) | |||||||
Cash dividends – common stock | (5,302 | ) | (5,162 | ) | (4,791 | ) | |||||||
Distributions to noncontrolling interests | (71 | ) | (99 | ) | (77 | ) | |||||||
Net sales (purchases) of treasury shares | 168 | (6,821 | ) | (6,389 | ) | ||||||||
Net Cash Used for Financing Activities | (3,546 | ) | (10,400 | ) | (14,295 | ) | |||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | 114 | (166 | ) | 120 | |||||||||
Net Change in Cash and Cash Equivalents | (631 | ) | 1,985 | (3,131 | ) | ||||||||
Cash and Cash Equivalents at January 1 | 9,347 | 7,362 | 10,493 | ||||||||||
Cash and Cash Equivalents at December 31 | $ | 8,716 | $ | 9,347 | $ | 7,362 | |||||||
FS-30
2009 | 2008 | 2007 | |||||||||||||||||||||||
Shares | Amount | Shares | Amount | Shares | Amount | ||||||||||||||||||||
Preferred Stock | – | $ | – | – | $ | – | – | $ | – | ||||||||||||||||
Common Stock | 2,442,677 | $ | 1,832 | 2,442,677 | $ | 1,832 | 2,442,677 | $ | 1,832 | ||||||||||||||||
Capital in Excess of Par | |||||||||||||||||||||||||
Balance at January 1 | $ | 14,448 | $ | 14,289 | $ | 14,126 | |||||||||||||||||||
Treasury stock transactions | 183 | 159 | 163 | ||||||||||||||||||||||
Balance at December 31 | $ | 14,631 | $ | 14,448 | $ | 14,289 | |||||||||||||||||||
Retained Earnings | |||||||||||||||||||||||||
Balance at January 1 | $ | 101,102 | $ | 82,329 | $ | 68,464 | |||||||||||||||||||
Net income attributable to Chevron Corporation | 10,483 | 23,931 | 18,688 | ||||||||||||||||||||||
Cash dividends on common stock | (5,302 | ) | (5,162 | ) | (4,791 | ) | |||||||||||||||||||
Adoption of new accounting standard for uncertain income tax positions | – | – | (35 | ) | |||||||||||||||||||||
Tax benefit from dividends paid on unallocated ESOP shares and other | 6 | 4 | 3 | ||||||||||||||||||||||
Balance at December 31 | $ | 106,289 | $ | 101,102 | $ | 82,329 | |||||||||||||||||||
Notes Receivable – Key Employees | $ | – | $ | – | $ | (1 | ) | ||||||||||||||||||
Accumulated Other Comprehensive Loss | |||||||||||||||||||||||||
Currency translation adjustment | |||||||||||||||||||||||||
Balance at January 1 | $ | (171 | ) | $ | (59 | ) | $ | (90 | ) | ||||||||||||||||
Change during year | 60 | (112 | ) | 31 | |||||||||||||||||||||
Balance at December 31 | $ | (111 | ) | $ | (171 | ) | $ | (59 | ) | ||||||||||||||||
Pension and other postretirement benefit plans | |||||||||||||||||||||||||
Balance at January 1 | $ | (3,909 | ) | $ | (2,008 | ) | $ | (2,585 | ) | ||||||||||||||||
Change to defined benefit plans during year | (399 | ) | (1,901 | ) | 685 | ||||||||||||||||||||
Adoption of new accounting standard for defined benefit pension and other postretirement plans | – | – | (108 | ) | |||||||||||||||||||||
Balance at December 31 | $ | (4,308 | ) | $ | (3,909 | ) | $ | (2,008 | ) | ||||||||||||||||
Unrealized net holding gain on securities | |||||||||||||||||||||||||
Balance at January 1 | $ | 13 | $ | 19 | $ | – | |||||||||||||||||||
Change during year | 2 | (6 | ) | 19 | |||||||||||||||||||||
Balance at December 31 | $ | 15 | $ | 13 | $ | 19 | |||||||||||||||||||
Net derivatives gain (loss) on hedge transactions | |||||||||||||||||||||||||
Balance at January 1 | $ | 143 | $ | 33 | $ | 39 | |||||||||||||||||||
Change during year | (60 | ) | 110 | (6 | ) | ||||||||||||||||||||
Balance at December 31 | $ | 83 | $ | 143 | $ | 33 | |||||||||||||||||||
Balance at December 31 | $ | (4,321 | ) | $ | (3,924 | ) | $ | (2,015 | ) | ||||||||||||||||
Deferred Compensation and Benefit Plan Trust | |||||||||||||||||||||||||
Deferred Compensation | |||||||||||||||||||||||||
Balance at January 1 | $ | (194 | ) | $ | (214 | ) | $ | (214 | ) | ||||||||||||||||
Net reduction of ESOP debt and other | 85 | 20 | – | ||||||||||||||||||||||
Balance at December 31 | (109 | ) | (194 | ) | (214 | ) | |||||||||||||||||||
Benefit Plan Trust (Common Stock) | 14,168 | (240 | ) | 14,168 | (240 | ) | 14,168 | (240 | ) | ||||||||||||||||
Balance at December 31 | 14,168 | $ | (349 | ) | 14,168 | $ | (434 | ) | 14,168 | $ | (454 | ) | |||||||||||||
Treasury Stock at Cost | |||||||||||||||||||||||||
Balance at January 1 | 438,445 | $ | (26,376 | ) | 352,243 | $ | (18,892 | ) | 278,118 | $ | (12,395 | ) | |||||||||||||
Purchases | 85 | (6 | ) | 95,631 | (8,011 | ) | 85,429 | (7,036 | ) | ||||||||||||||||
Issuances – mainly employee benefit plans | (3,575 | ) | 214 | (9,429 | ) | 527 | (11,304 | ) | 539 | ||||||||||||||||
Balance at December 31 | 434,955 | $ | (26,168 | ) | 438,445 | $ | (26,376 | ) | 352,243 | $ | (18,892 | ) | |||||||||||||
Total Chevron Corporation Stockholders’ Equity at December 31 | $ | 91,914 | $ | 86,648 | $ | 77,088 | |||||||||||||||||||
Noncontrolling Interests | $ | 647 | $ | 469 | $ | 204 | |||||||||||||||||||
Total Equity | $ | 92,561 | $ | 87,117 | $ | 77,292 | |||||||||||||||||||
FS-31
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.
FS-32
Note 1Summary of Significant Accounting Policies - Continued Properties, Plant and EquipmentThe successful efforts method is used for crude-oil and natural-gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude-oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 19, beginning on page FS-50, for additional discussion of accounting for suspended exploratory well costs. Long-lived assets to be held and used, including proved crude-oil and natural-gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted future net before-tax cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset, significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved crude-oil and natural-gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country, concession, development area or field basis, as appropriate. In the refining, marketing, transportation and chemicals areas, impairment reviews are generally done on the basis of a refinery, a plant, a marketing area or marketing assets by country. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. As required under accounting standards for asset retirement and environmental obligations (Accounting Standards Codification (ASC) 410), the fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 23, on page FS-60, relating to AROs. Depreciation and depletion of all capitalized costs of proved crude-oil and natural-gas producing properties, except mineral interests, are expensed using the unit-of-production method generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Depreciation and depletion expenses for mining assets are determined using the unit-of-production method as the proved reserves are produced. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method generally is used to depreciate international plant and equipment and to amortize all capitalized leased assets. Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses and from sales as “Other income.” Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized. |
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
Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||
Note 1Summary of Significant Accounting Policies - Continued following accounting standards for asset retirement and environmental obligations. Refer to Note 23, on page FS-60, for a discussion of the company’s AROs. For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured. Currency TranslationThe 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 “Currency translation adjustment” on the Consolidated Statement of Equity. Revenue RecognitionRevenues 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 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. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income. Stock Options and Other Share-Based CompensationThe company issues stock options and other share-based compensation to its employees and accounts for these transactions under the accounting standards for share-based compensation (ASC 718). 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 value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period an employee becomes eligible to retain the award at retirement. Stock options and stock appreciation rights granted under the company’s Long-Term Incentive Plan have graded vesting provisions by which one-third of each award vests on the first, second and third anniversaries of the date of grant. The company amortizes these graded awards on a straight-line basis. Note 2 Noncontrolling Interests The company adopted accounting standards for noncontrolling interests (ASC 810) in the consolidated financial statements effective January 1, 2009, and retroactive to the earliest period presented. Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income. The term “earnings” is defined as “Net Income Attributable to Chevron Corporation.” | |||||||||
2009 | 2008 | 2007 | |||||||||||
Balance at January 1 | $ | 469 | $ | 204 | $ | 209 | |||||||
Net income | 80 | 100 | 107 | ||||||||||
Distributions to noncontrolling interests | (71 | ) | (99 | ) | (77 | ) | |||||||
Other changes, net | 169 | 264 | (35 | ) | |||||||||
Balance at December 31 | $ | 647 | $ | 469 | $ | 204 | |||||||
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
Note Information Relating to the Consolidated Statements of Cash Flows
In accordance with accounting standards for cash-flow classifications for stock options (ASC 718), the “Net (increase) decrease in operating working capital” includes reductions of $25, $106 and $96 for excess income tax benefits associated with stock options exercised during 2009, 2008 and 2007, respectively. These amounts are offset by an equal amount in “Net sales (purchases) of treasury shares.” The “Net sales (purchases) of treasury shares” represents the cost of common shares purchased less the cost of shares issued for share-based compensation plans. Purchases totaled $6, $8,011 and $7,036 in 2009, 2008 and 2007, respectively. Purchases in 2008 and 2007 included shares purchased under the company’s common stock repurchase programs. In 2009, “Net sales (purchases) of other short-term investments” consisted of $123 in restricted cash associated with capital-investment projects at the company’s Pascagoula, Mississippi refinery and the Angola liquefied-natural-gas project that was invested in short-term securities and reclassified from “Cash and cash equivalents” to “Deferred charges and other assets” on the Consolidated Balance Sheet. The company issued $350 and $650, in 2009 and 2007 respectively, of tax exempt Mississippi Gulf Opportunity Zone Bonds as a source of funds for Pascagoula Refinery projects. The Consolidated Statement of Cash Flows for 2009 excludes changes to the Consolidated Balance Sheet that did not affect cash. In 2008, “Net sales (purchases) of treasury shares” excludes $680 of treasury shares acquired in exchange for a U.S. upstream property and $280 in cash. The carrying value of this property in “Properties, plant and equipment” on the Consolidated Balance Sheet was not significant. In 2008, a $2,450 increase in “Accrued liabilities” and a corresponding increase to “Properties, plant and equipment, at cost” were considered non-cash transactions and excluded from “Net (increase) decrease in operating working capital” and “Capital expenditures.” In 2009, the payments related to these “Accrued liabilities” were excluded from “Net (increase) decrease in operating working capital” and were reported as “Capital expenditures.” The amount is related to upstream operating agreements outside the United States. “Capital expenditures” in 2008 excludes a $1,400 increase in “Properties, plant and equipment” related to the acquisition of an additional interest in an equity affiliate that required a change to the consolidated method of accounting for the investment during 2008. This addition was offset primarily by reductions in “Investments and advances” and working capital and an increase in “Non-current deferred income tax” liabilities. Refer also to Note 23, on page FS-60, for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2009. |
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
Additions to properties, plant and equipment1 | $ | 16,107 | $ | 18,495 | $ | 16,127 | |||||||
Additions to investments | 942 | 1,051 | 881 | ||||||||||
Current-year dry-hole expenditures | 468 | 320 | 418 | ||||||||||
Payments for other liabilities and assets, net2 | 2,326 | (200 | ) | (748 | ) | ||||||||
Capital expenditures | 19,843 | 19,666 | 16,678 | ||||||||||
Expensed exploration expenditures | 790 | 794 | 816 | ||||||||||
Assets acquired through capital lease obligations and other financing obligations | 19 | 9 | 196 | ||||||||||
Capital and exploratory expenditures, excluding equity affiliates | 20,652 | 20,469 | 17,690 | ||||||||||
Company’s share of expenditures by equity affiliates | 1,585 | 2,306 | 2,336 | ||||||||||
Capital and exploratory expenditures, including equity affiliates | $ | 22,237 | $ | 22,775 | $ | 20,026 | |||||||
1 Excludes noncash additions of $985 in 2009, $5,153 in 2008 and $3,560 in 2007. | ||
2 2009 includes payments of $2,450 for accruals recorded in 2008. |
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
Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Note Summarized Financial Data – Chevron U.S.A. Inc. Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. During 2008, Chevron implemented legal reorganizations in which certain Chevron subsidiaries transferred assets to or under CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganizations as if they had occurred on January 1, 2007. However, the financial information in the following table may not reflect the financial position and operating results in the future or the historical results in the periods presented if the reorganization actually had occurred on that date. The summarized financial information for CUSA and its consolidated subsidiaries is as follows:
The amount for the years ended December 31, 2008, and December 31, 2007, for “Net income attributable to CUSA” and the balances at December 31, 2008, for “Other liabilities” and “Total CUSA net equity” have been adjusted by immaterial amounts associated with the allocation of income-tax liabilities among Chevron Corporation subsidiaries. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
Sales and other operating revenues | $ | 683 | $ | 1,022 | $ | 667 | |||||||
Total costs and other deductions | 810 | 947 | 713 | ||||||||||
Net income attributable to CTC | (124 | ) | 120 | (39 | ) | ||||||||
At December 31 | |||||||||
2009 | 2008 | ||||||||
Current assets | $ | 377 | $ | 482 | |||||
Other assets | 173 | 172 | |||||||
Current liabilities | 115 | 98 | |||||||
Other liabilities | 90 | 88 | |||||||
Total CTC net equity | 345 | 468 | |||||||
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
Sales and other operating revenues | $ | 12,013 | $ | 14,329 | $ | 8,919 | |||||||
Costs and other deductions | 6,044 | 5,621 | 3,387 | ||||||||||
Net income attributable to TCO | 4,178 | 6,134 | 3,952 | ||||||||||
At December 31 | |||||||||
2009 | 2008 | ||||||||
Current assets | $ | 3,190 | $ | 2,740 | |||||
Other assets | 12,022 | 12,240 | |||||||
Current liabilities | 2,426 | 1,867 | |||||||
Other liabilities | 4,484 | 4,759 | |||||||
Total TCO net equity | 8,302 | 8,354 | |||||||
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
Note Lease Commitments Certain noncancelable leases are classified as capital leases, and the leased assets are included as part of “Properties, plant and equipment, at cost” on the Consolidated Balance Sheet. Such leasing arrangements involve tanker charters, crude-oil production and processing equipment, service stations, office buildings, and other facilities. Other leases are classified as operating leases and are not capitalized. The payments on such leases are recorded as expense. Details of the capitalized leased assets are as follows: |
At December 31 | |||||||||
2009 | 2008 | ||||||||
Upstream | $ | 510 | $ | 491 | |||||
Downstream | 332 | 399 | |||||||
Chemicals and all other | 171 | 171 | |||||||
Total | 1,013 | 1,061 | |||||||
Less: Accumulated amortization | 585 | 522 | |||||||
Net capitalized leased assets | $ | 428 | $ | 539 | |||||
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
Minimum rentals | $ | 2,179 | $ | 2,984 | $ | 2,419 | |||||||
Contingent rentals | 7 | 6 | 6 | ||||||||||
Total | 2,186 | 2,990 | 2,425 | ||||||||||
Less: Sublease rental income | 41 | 41 | 30 | ||||||||||
Net rental expense | $ | 2,145 | $ | 2,949 | $ | 2,395 | |||||||
At December 31 | |||||||||
Operating | Capital | ||||||||
Leases | Leases | ||||||||
Year: 2010 | 568 | 90 | |||||||
2011 | 438 | 81 | |||||||
2012 | 406 | 87 | |||||||
2013 | 372 | 60 | |||||||
2014 | 347 | 44 | |||||||
Thereafter | 1,233 | 137 | |||||||
Total | $ | 3,364 | $ | 499 | |||||
Less: Amounts representing interest and executory costs | (104 | ) | |||||||
Net present values | 395 | ||||||||
Less: Capital lease obligations included in short-term debt | (94 | ) | |||||||
Long-term capital lease obligations | $ | 301 | |||||||
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.
FS-37
Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 9Fair Value Measurements - Continued | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring fair-value measurements. Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities. In 2009, the company used Level 3 inputs to determine the fair value of certain nonrecurring nonfinancial assets. The fair-value hierarchy for recurring assets and liabilities measured at fair value at December 31, 2009, and December 31, 2008, is as follows: Assets and Liabilities Measured at Fair Value on a Recurring Basis
Marketable SecuritiesThe company calculates fair value for its marketable securities based on quoted market prices for identical assets and liabilities. The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2009. Marketable securities had average maturities of less than one year. DerivativesThe company records its derivative instruments – other than any commodity derivative contracts that are designated as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with virtually all the offsetting amount to the Consolidated Statement of Income. For derivatives with identical or similar provisions as contracts that are publicly traded on a regular basis, the company uses the market values of the publicly traded instruments as an input for fair-value calculations. The company’s derivative instruments principally include crude-oil, natural-gas and refined-product futures, swaps, options and forward contracts. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options, and forward contracts principally with financial institutions and other oil and gas companies, the fair values for which are obtained from third-party broker quotes, industry pric- ing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information. The company incorporates internal review, evaluation and assessment procedures, including a comparison of Level 2 fair values derived from the company’s internally developed forward curves (on a sample basis) with the pricing information to document reasonable, logical and supportable fair-value determinations and proper level of classification. Impairments of “Properties, plant and equipment”During 2009 and in accordance with the accounting standard for the impairment or disposal of long-lived assets (ASC 360), long-lived assets “held and used” with a carrying amount of $949 were written down to a fair value of $490, resulting in a before-tax loss of $459. The fair values were determined from internal cash-flow models, using discount rates consistent with those used by the company to evaluate cash flows of other assets of a similar nature. Long-lived assets “held for sale” with a carrying amount of $160 were written down to a fair value of $68, resulting in a before-tax loss of $92. The fair values were determined based on bids received from prospective buyers. FS-38 Note The fair-value hierarchy for nonrecurring assets and liabilities measured at fair value during 2009 is presented in the following table. Assets and Liabilities Measured at Fair Value on a Non-recurring Basis
Assets and Liabilities Not Required to Be Measured at Fair ValueThe company holds cash equivalents in U.S. and non-U.S. portfolios. The instruments held are primarily time deposits and money market funds. The fair values reflect the cash that would have been received or paid if the instruments were settled atyear-end. Cash equivalents had carrying/fair values of $6,396 and $7,058 at December 31, 2009 and 2008, respectively, and average maturities under 90 days. The balance at December 31, 2009, includes $123 of investments for restricted funds related to an international upstream development project and Pascagoula Refinery projects, which are included in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $5,705 and $1,221 had estimated fair values of $6,229 and $1,414 at December 31, 2009 and 2008, respectively. Fair values of other financial instruments at the end of 2009 and 2008 were not material. Note 10 Financial and Derivative Instruments Derivative Commodity InstrumentsChevron is exposed to market risks related to price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks. The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the pur- chase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company refineries. From time to time, the company also uses derivative commodity instruments for limited trading purposes. The company’s derivative commodity instruments principally include crude-oil, natural-gas and refined-product futures, swaps, options and forward contracts. None of the company’s derivative instruments is designated as a hedging instrument, although certain of the company’s affiliates make such designation. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities. The company uses International Swaps and Derivatives Association agreements to govern derivative contracts with certain counterparties to mitigate credit risk. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required. When the company is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the net mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and is a reasonable measure of the company’s credit risk exposure. The company also uses other netting agreements with certain counterparties with which it conducts significant transactions to mitigate credit risk. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
company uses to value an asset or a liability. The three levels of the fair-value hierarchy
The fair-value hierarchy for assets and liabilities measured at fair value at December 31, 2008, is as follows:
Assets and Liabilities Measured atFair 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.
Asset Derivatives – Fair Value | Liability Derivatives – Fair Value | |||||||||||||||||||||||
Type of | Balance Sheet | At December 31 | At December 31 | Balance Sheet | At December 31 | At December 31 | ||||||||||||||||||
Derivative Contract | Classification | 2009 | 2008 | Classification | 2009 | 2008 | ||||||||||||||||||
Foreign Exchange | Accounts and notes receivable, net | $ | – | $ | 11 | Accrued liabilities | $ | – | $ | 89 | ||||||||||||||
Commodity | Accounts and notes receivable, net | 99 | 764 | Accounts payable | 73 | 344 | ||||||||||||||||||
Commodity | Long-term receivables, net | 28 | 30 | Deferred credits and other noncurrent obligations | 28 | 83 | ||||||||||||||||||
$ | 127 | $ | 805 | $ | 101 | $ | 516 | |||||||||||||||||
FS-39
FS-38
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 | |||||
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
Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 10 Financial and Derivative Instruments - Continued | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Consolidated Statement of Income: The Effect of Derivatives Not Designated as Hedging Instruments
Foreign CurrencyThe company may enter into currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open currency derivative contracts at December 31, 2009. Interest RatesThe company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Historically, under the terms of the swaps, net cash settlements were 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, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2009, the company had no interest rate swaps. The company’s only interest rate swaps on fixed-rate debt matured in January 2009. Concentrations of Credit RiskThe 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. The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a result, the company believes concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, requiring Letters of Credit is a principal method used to support sales to customers. Note Operating Segments and Geographic Data | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 | |||||||
Although each subsidiary of The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in ASC 280). The CODM is the company’s Executive Committee, a committee of senior officers that includes the Chief Executive Officer and that, in turn, reports to the Board of Directors of Chevron Corporation. The operating segments represent components of the Segment managers for the reportable segments are directly accountable to and maintain regular contact with the company’s |
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.
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
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 11Restructuring 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 12Investments 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 | |||||||||||
FS-41
Note members of the Executive Committee also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM. “All Other” activities include 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 (through May 2007, when Chevron sold its interest). The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States). Segment EarningsThe 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.” Earnings by major operating area are presented in the following table:
Segment AssetsSegment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 2009 and 2008 are as follows:
Segment Sales and Other Operating RevenuesOperating segment sales and other operating revenues, including internal transfers, for the years 2009, 2008 and 2007, are presented in the table on the following page. Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of refined products, crude oil and natural gas liquids. Revenues | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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-
FS-41
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
Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 11 Operating Segments and Geographic Data - Continued for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuels. “All Other” activities include revenues from mining operations, power generation businesses, insurance operations, real estate activities and technology companies. 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 2009, 2008 and 2007.
Segment Income TaxesSegment income tax expense for the years 2009, 2008 and 2007 is as follows:
Other Segment InformationAdditional information for the segmentation of major equity affiliates is contained in Note 12, beginning on page FS-43. Information related to properties, plant and equipment by segment is contained in Note 13, on page FS-45. FS-42 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Note 12 Investments and Advances Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, is shown in the table below. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.”
Descriptions of major affiliates, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows: Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), a joint venture formed in 1993 to develop the Tengiz and Korolev crude-oil fields in Kazakhstan over a 40-year period. At December 31, 2009, the company’s carrying value of its investment in TCO was about $200 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. See Note 7, on page FS-36, for summarized financial information for 100 percent of TCO. PetropiarChevron 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, 2009, the company’s carrying value of its investment in Petropiar was approximately $195 less than the amount of underlying equity in Petropiar’s 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. PetroboscanChevron 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, 2009, the company’s carrying value of its investment in Petroboscan was approximately $275 higher than the amount of underlying equity in Petroboscan’s 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 CorporationChevron 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 ConsortiumChevron 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. 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, 2009, FS-43 Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 12Investments and Advances - Continued the fair value of Chevron’s share of CAL common stock was approximately $1,120. Colonial Pipeline CompanyChevron 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, 2009, the company’s carrying value of its investment in Colonial Pipeline was approximately $550 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 LLCChevron owns 50 percent of Chevron Phillips Chemical Company LLC. The other half is owned by ConocoPhillips Corporation. Other Information“Sales and other operating revenues” on the Consolidated Statement of Income includes $10,391, $15,390 and $11,555 with affiliated companies for 2009, 2008 and 2007, respectively. “Purchased crude oil and products” includes $4,631, $6,850 and $5,464 with affiliated companies for 2009, 2008 and 2007, respectively. |
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 | |||||||||||||
FS-44Note 13Properties, Plant 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 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 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 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 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 $ 173,299 $ 154,084 $ 137,747 $ 91,780 $ 78,610 $ 68,858 $ 23,593 $ 19,048 $ 13,027 $ 9,528 $ 8,708 $ 7,506 1 Net of dry hole expense related to prior years’ expenditures of $55, $89 and $120 in 2008, 2007 and 2006, respectively.2 Depreciation expense includes accretion expense of $430, $399 and $275 in 2008, 2007 and 2006, respectively.3 Primarily mining operations, power generation businesses, real estate assets and management information systems.Note 14Accounting for Buy/Sell ContractsThe company adopted the accounting prescribed by Emerging Issues Task Force (EITF) Issue No. 04-13,Accounting for Purchases and Sales of Inventory with the Same Counterparty(Issue 04-13), on a prospective basis from April 1, 2006. Issue 04-13 requires that two or more legally separate exchange transactions with the same counterparty, including buy/sell transactions, be combined and considered as a single arrangement for purposes of applying the provisions of Accounting Principles Board Opinion No. 29,Accounting for Nonmonetary Transactions,when the transactions are entered into “in Affiliates Chevron Share Year ended December 31 2009 2008 2007 2009 2008 2007 Total revenues $ 81,995 $ 112,707 $ 94,864 $ 39,280 $ 54,055 $ 46,579 Income before income tax expense 11,083 17,500 12,510 4,511 7,532 5,836 Net income attributable to affiliates 8,261 12,705 9,743 3,285 5,524 4,550 Current assets $ 27,111 $ 25,194 $ 26,360 $ 11,009 $ 10,804 $ 11,914 Noncurrent assets 55,363 51,878 48,440 21,361 20,129 19,045 Current liabilities 17,450 17,727 19,033 7,833 7,474 9,009 Noncurrent liabilities 21,531 21,049 22,757 5,106 4,533 3,745 Total affiliates’ net equity $ 43,493 $ 38,296 $ 33,010 $ 19,431 $ 18,926 $ 18,205 contemplation” of one another. In prior periods, the company accounted for buy/sell transactions in the Consolidated Statement of Income as a monetary transaction – purchases were reported as “Purchased crude oil and products”; sales were reported as “Sales and other operating revenues.” With the company’s adoption of Issue 04-13, buy/sell transactions beginning in the second quarter 2006 are netted against each other on the Consolidated Statement of Income, with no effect on net income. The amount associated with buy/sell transactions in the first quarter 2006 is shown as a footnote to the Consolidated Statement of Income on page FS-27.
FS-43
At December 31 | Year ended December 31 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Investment at Cost | Net Investment | Additions at Cost2 | Depreciation Expense3 | ||||||||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | ||||||||||||||||||||||||||||||||||||||||
Upstream | |||||||||||||||||||||||||||||||||||||||||||||||||||
United States | $ | 57,645 | $ | 54,156 | $ | 50,991 | $ | 21,885 | $ | 22,294 | $ | 19,850 | $ | 3,496 | $ | 5,374 | $ | 5,725 | $ | 3,963 | $ | 2,683 | $ | 2,700 | |||||||||||||||||||||||||||
International | 93,177 | 84,282 | 71,408 | 54,253 | 51,140 | 43,431 | 9,750 | 13,177 | 10,512 | 6,651 | 5,441 | 4,605 | |||||||||||||||||||||||||||||||||||||||
Total Upstream | 150,822 | 138,438 | 122,399 | 76,138 | 73,434 | 63,281 | 13,246 | 18,551 | 16,237 | 10,614 | 8,124 | 7,305 | |||||||||||||||||||||||||||||||||||||||
Downstream | |||||||||||||||||||||||||||||||||||||||||||||||||||
United States | 18,915 | 17,394 | 15,807 | 10,089 | 8,977 | 7,685 | 1,871 | 2,032 | 1,514 | 664 | 629 | 509 | |||||||||||||||||||||||||||||||||||||||
International | 12,319 | 11,587 | 10,471 | 6,806 | 6,001 | 4,690 | 1,424 | 2,285 | 519 | 437 | 469 | 633 | |||||||||||||||||||||||||||||||||||||||
Total Downstream | 31,234 | 28,981 | 26,278 | 16,895 | 14,978 | 12,375 | 3,295 | 4,317 | 2,033 | 1,101 | 1,098 | 1,142 | |||||||||||||||||||||||||||||||||||||||
Chemicals | |||||||||||||||||||||||||||||||||||||||||||||||||||
United States | 730 | 725 | 678 | 331 | 338 | 308 | 25 | 50 | 40 | 31 | 19 | 19 | |||||||||||||||||||||||||||||||||||||||
International | 913 | 828 | 815 | 545 | 496 | 453 | 85 | 72 | 53 | 35 | 33 | 26 | |||||||||||||||||||||||||||||||||||||||
Total Chemicals | 1,643 | 1,553 | 1,493 | 876 | 834 | 761 | 110 | 122 | 93 | 66 | 52 | 45 | |||||||||||||||||||||||||||||||||||||||
All Other4 | |||||||||||||||||||||||||||||||||||||||||||||||||||
United States | 4,569 | 4,310 | 3,873 | 2,548 | 2,523 | 2,179 | 354 | 598 | 680 | 325 | 250 | 215 | |||||||||||||||||||||||||||||||||||||||
International | 20 | 17 | 41 | 11 | 11 | 14 | 3 | 5 | 5 | 4 | 4 | 1 | |||||||||||||||||||||||||||||||||||||||
Total All Other | 4,589 | 4,327 | 3,914 | 2,559 | 2,534 | 2,193 | 357 | 603 | 685 | 329 | 254 | 216 | |||||||||||||||||||||||||||||||||||||||
Total United States | 81,859 | 76,585 | 71,349 | 34,853 | 34,132 | 30,022 | 5,746 | 8,054 | 7,959 | 4,983 | 3,581 | 3,443 | |||||||||||||||||||||||||||||||||||||||
Total International | 106,429 | 96,714 | 82,735 | 61,615 | 57,648 | 48,588 | 11,262 | 15,539 | 11,089 | 7,127 | 5,947 | 5,265 | |||||||||||||||||||||||||||||||||||||||
Total | $ | 188,288 | $ | 173,299 | $ | 154,084 | $ | 96,468 | $ | 91,780 | $ | 78,610 | $ | 17,008 | $ | 23,593 | $ | 19,048 | $ | 12,110 | $ | 9,528 | $ | 8,708 | |||||||||||||||||||||||||||
1 Other than the United States and Nigeria, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2009 and 2008. Only the United States had more than 10 percent in 2007. Nigeria had net PP&E of $12,463 and $10,730 for 2009 and 2008, respectively. | |||||||||
2 Net of dry hole expense related to prior years’ expenditures of $84, $55 and $89 in 2009, 2008 and 2007, respectively. | |||||||||
3 Depreciation expense includes accretion expense of $463, $430 and $399 in 2009, 2008 and 2007, respectively. | |||||||||
4 Primarily mining operations, power generation businesses, real estate assets and management information systems. | |||||||||
FS-45
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
FS-44
Note 16Taxes
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 | ||||||||
FS-45
Note | |||||||||
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
Taxes on income | |||||||||||||
U.S. Federal | |||||||||||||
Current | $ | 128 | $ | 2,879 | $ | 1,446 | |||||||
Deferred | (147 | ) | 274 | 225 | |||||||||
State and local | |||||||||||||
Current | 216 | 528 | 356 | ||||||||||
Deferred | 14 | 141 | (18 | ) | |||||||||
Total United States | 211 | 3,822 | 2,009 | ||||||||||
International | |||||||||||||
Current | 7,154 | 15,021 | 11,416 | ||||||||||
Deferred | 600 | 183 | 54 | ||||||||||
Total International | 7,754 | 15,204 | 11,470 | ||||||||||
Total taxes on income | $ | 7,965 | $ | 19,026 | $ | 13,479 | |||||||
Year ended December 31 | |||||||||||||
2009 | 2008 | 2007 | |||||||||||
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 | 10.4 | 10.1 | 8.2 | ||||||||||
State and local taxes on income, net of U.S. federal income tax benefit | 0.9 | 1.0 | 0.8 | ||||||||||
Prior-year tax adjustments | (0.3 | ) | (0.1 | ) | 0.3 | ||||||||
Tax credits | (1.1 | ) | (0.5 | ) | (0.4 | ) | |||||||
Effects of enacted changes in tax laws | 0.1 | (0.6 | ) | (0.3 | ) | ||||||||
Other | (2.0 | ) | (0.7 | ) | (1.8 | ) | |||||||
Effective tax rate | 43.0 | % | 44.2 | % | 41.8 | % | |||||||
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 | ||||||||
FS-46
Note The company’s effective tax rate decreased from 44.2 percent in 2008 to 43.0 percent in 2009. The rate was lower in 2009 mainly due to the effect of deferred tax benefits and relatively low tax rates on asset sales, both related to an international upstream project. In addition, a greater proportion of before-tax income was earned in 2009 by equity affiliates than in 2008. (Equity-affiliate income is reported as a single amount on an after-tax basis on the Consolidated Statement of Income.) Partially offsetting these items was the effect of a greater proportion of income earned in 2009 in tax jurisdictions with higher tax rates. The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities. The reported deferred tax balances are composed of the following:
Deferred tax liabilities at the end of 2009 increased by approximately $400 from year-end 2008. The increase was primarily related to increased temporary differences for properties, plant and equipment. Deferred tax assets were essentially unchanged in 2009. Increases related to additional foreign tax credits arising from earnings in high-tax-rate international jurisdictions (which were substantially offset by valuation allowances) and to inventory-related temporary differences. These effects were offset by reductions in deferred credits and tax loss carryforwards primarily resulting from the usage of tax benefits in international tax jurisdictions. The overall valuation allowance relates to deferred tax assets for foreign tax credit carryforwards, tax loss carryforwards and temporary differences. It reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. Tax loss carryforwards exist in many international jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2010 through 2036. Foreign tax credit carryforwards of $5,387 will expire between 2010 and 2019. At December 31, 2009 and 2008, deferred taxes were classified on the Consolidated Balance Sheet as follows:
Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely. Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled $20,458 at December 31, 2009. This amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of taxes that might be payable on the eventual remittance of earnings that are intended to be reinvested indefinitely. At the end of 2009, deferred income taxes were recorded for the undistributed earnings of certain international operations for which the company no longer intends to indefinitely reinvest the earnings. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested. Uncertain Income Tax Positions Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes (ASC 740-10-20) refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. |
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.
FS-47
Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Note 15 Taxes - Continued The following table indicates the changes to the company’s unrecognized tax benefits for the year ended December 31, 2009. The term “unrecognized tax benefits” in the accounting standards for income taxes (ASC 740-10-20) refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included.
Although unrecognized tax benefits for individual tax positions may increase or decrease during 2010, the company believes that no change will be individually significant during 2010. Approximately 90 percent of the $3,195 of unrecognized tax benefits at December 31, 2009, would have an impact on the effective tax rate if subsequently recognized. Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of December 31, 2009. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – 2005, Nigeria – 1994, Angola – 2001 and Saudi Arabia – 2003. On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2009, accruals of $232 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $276 as of year-end 2008. Income tax (benefit) expense associated with interest and penalties was $(20), $79 and $70 in 2009, 2008 and 2007, respectively. Taxes Other Than on Income
Note Short-Term Debt
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
FS-48
FS-49
Of the $1,871 of exploratory well costs capitalized for more than one year at December 31, 2009, $1,143 (28 projects) is related to projects that had drilling activities under way or firmly planned for the near future. The $728 balance is related to 18 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.
FS-50
Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, 2009 and 2008, include:
Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $6,454 and $5,831 at the end of 2009 and 2008, respectively. These amounts consisted of:
The accumulated benefit obligations for all U.S. and international pension plans were $8,707 and $4,029, respectively, at December 31, 2009, and $7,376 and $3,273, respectively, at December 31, 2008. Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2009 and 2008, was:
FS-53
The components of net periodic benefit cost and amounts recognized in other comprehensive income for 2009, 2008 and 2007 are shown in the table below:
Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2009, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 11, 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 2010, the company estimates actuarial losses of $318, $102 and $26 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respec- tively. In addition, the company estimates an additional $220 will be recognized from “Accumulated other comprehensive loss” during 2010 related to lump-sum settlement costs from U.S. pension plans. The weighted average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, 2009, was approximately eight and 12 years for U.S. and international pension plans, respectively, and eight years for other postretirement benefit plans. During 2010, the company estimates prior service (credits) costs of $(7), $27 and $(74) will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively.
FS-54
Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:
Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the company’s estimated long-term rates of return are consistent with these studies. There have been no changes in the expected long-term rate of return on plan assets since 2002 for U.S. plans, which account for 69 percent of the company’s pension plan assets. At December 31, 2009, the estimated long-term rate of return on U.S. pension plan assets was 7.8 percent. The market-related value of assets of the major U.S. pension plan used in the determination of pension expense was based on the market values in the three months preceding the year-end measurement date, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense. 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, 2009, the company selected a 5.3 percent discount rate for the U.S. pension plan and 5.8 percent for the U.S. postretirement benefit plan. 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 2009. The discount rates at the end of 2008 and 2007 were 6.3 percent for the U.S. pension plan and the OPEB plan. Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2009, for the main U.S. postretirement medical plan, the assumed health care cost-trend rates start with 7 percent in 2010 and gradually decline to 5 percent for 2018 and beyond. For this measurement at December 31, 2008, the assumed health care cost-trend rates started with 7 percent in 2009 and gradually declined to 5 percent for 2017 and beyond. In both measurements, the annual increase to company contributions was capped at 4 percent. Assumed health care cost-trend rates can have a significant effect on the amounts reported for retiree health care costs. The impact is mitigated by the 4 percent cap on the company’s medical contributions for the primary U.S. plan. A one-percentage-point change in the assumed health care cost-trend rates would have the following effects:
Plan Assets and Investment Strategy Effective December 31, 2009, the company implemented the expanded disclosure requirements for the plan assets of defined benefit pension and OPEB plans (ASC 715) 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 unobservable inputs on changes in plan assets for the period; and significant concentrations of risk within plan assets. The fair-value hierarchy of inputs the company uses to value the pension assets is divided into three levels:
FS-55
Level 1: Fair values of these assets are measured using unadjusted quoted prices for the assets or the prices of identical assets in active markets that the plans have the ability to access. Level 2: Fair values of these assets are measured based on quoted prices for similar assets in active markets; quoted prices for identical or similar assets in inactive markets; inputs other than quoted prices that are observable for the asset; and inputs that are derived principally from or corroborated by observable market data by correlation or other means. If the asset has a contractual term, the Level 2 input is observable for substantially the full term of the asset. The fair values for Level 2 assets are generally obtained from third-party broker quotes, independent pricing services and exchanges. Level 3: Inputs to the fair value measurement are unobservable for these assets. Valuation may be performed using a financial model with estimated inputs entered into the model. The fair value measurements of the company’s pension plans for 2009 are below:
The effect of fair-value measurements using significant unobservable inputs on changes in Level 3 plan assets for the period are outlined below:
FS-56
The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate liquidity for benefit payments and portfolio management. The company’s U.S. and U.K. pension plans comprise 84 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plan’s investment performance, long-term asset allocation policy benchmarks have been established. For the primary U.S. pension plan, the Chevron Board of Directors has established the following approved asset allocation ranges: Equities 40-70 percent, Fixed Income and Cash 20-60 percent, Real Estate 0-15 percent, and Other 0-5 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines, which are reviewed regularly: Equities 60-80 percent and Fixed Income and Cash 20–40 percent. The other significant international pension plans also have established maximum and minimum asset allocation ranges that vary by plan. Actual asset allocation within approved ranges is based on a variety of current economic and market conditions and consideration of specific asset category risk. There are no significant concentrations of risk in plan assets due to the diversification of investment categories. The company does not prefund its OPEB obligations. Cash Contributions and Benefit Payments In 2009, the company contributed $1,494 and $245 to its U.S. and international pension plans, respectively. In 2010, the company expects contributions to be approximately $600 and $300 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 $208 in 2010, as compared with $187 paid in 2009. The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:
Employee Savings Investment PlanEligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP). Charges to expense for the ESIP represent the company’s contributions to the plan, which are funded either through the purchase of shares of common stock on the open market or through the release of common stock held in the leveraged employee stock ownership plan (LESOP), which is described in the section that follows. Total company matching contributions to employee accounts within the ESIP were $257, $231 and $206 in 2009, 2008 and 2007, respectively. This cost was reduced by the value of shares released from the LESOP totaling $184, $40 and $33 in 2009, 2008 and 2007, respectively. The remaining amounts, totaling $73, $191 and $173 in 2009, 2008 and 2007, respectively, represent open market purchases. 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. As permitted by accounting standards for share-based compensation (ASC 718), the debt of the LESOP is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” on the Consolidated Balance Sheet and the Consolidated Statement of Equity. The company reports compensation expense equal to LESOP debt principal repayments less dividends received and used by the LESOP for debt service. Interest accrued on LESOP debt is recorded as interest expense. Dividends paid on LESOP shares are reflected as a reduction of retained earnings. All LESOP shares are considered outstanding for earnings-per-share computations. Total credits to expense for the LESOP were $3, $1 and $1 in 2009, 2008 and 2007, respectively. The net credit for the respective years was composed of credits to compensation expense of $15, $15 and $17 and charges to interest expense for LESOP debt of $12, $14 and $16. Of the dividends paid on the LESOP shares, $110, $35 and $8 were used in 2009, 2008 and 2007, respectively, to service LESOP debt. No contributions were required in 2009, 2008 or 2007 as dividends received by the LESOP were sufficient to satisfy LESOP debt service. FS-57
FS-59
|