In accordance with Statement of FAS 69, Disclosures About Oil and Gas Producing Activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V through VII present information on the company's estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Chad, Republic of the Congo and Democratic Republic of the Congo. The Asia-Pacific geographic area includes activities principally in Australia, Azerbaijan, Bangladesh, China, Kazakhstan, Myanmar, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the Philippines, and Thailand. The international "Other" geographic category includes activities in Argentina, Brazil, Canada, Colombia, Denmark, the Netherlands, Norway, Trinidad and Tobago, Venezuela, the United Kingdom, and other countries. Amounts for TCO represent Chevron's 50 percent equity share of Tengizchevroil, an exploration and production partnership in the Republic of Kazakhstan. The affiliated companies "Other" amounts are composed of the company's equity interests in Venezuela, Angola and Russia. Refer to Note 11 for a discussion of the company's major equity affiliates.

Table I — Costs Incurred in Exploration, Property Acquisitions and Development 1

Consolidated Companies
United States International Affiliated Companies
Millions of dollars Calif. Gulf of Mexico Other Total U.S. Africa Asia-Pacific Indonesia Other Total
Int'l.		 Total TCO Other
1 Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 23, "Asset Retirement Obligations."
2 Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions.
3 Includes $99, $160 and $160 costs incurred prior to assignment of proved reserves in 2007, 2006 and 2005, respectively.
Year Ended Dec. 31, 2007
Exploration
Wells $4 $430 $18 $452 $202 $156 $3 $195 $556 $1,008 $– $7
Geological and geophysical – 59 14 73 136 48 11 98 293 366 – –
Rentals and other – 128 5 133 70 120 50 79 319 452 – –
Total exploration 4 617 37 658 408 324 64 372 1,168 1,826 – 7
Property acquisitions2
Proved 10 220 13 243 5 92 – (2) 95 338 – –
Unproved 35 75 3 113 8 35 – 24 67 180 – –
Total property acquisitions 45 295 16 356 13 127 – 22 162 518 – –
Development3 1,198 2,237 1,775 5,210 4,176 1,897 620 1,504 8,197 13,407 832 64
Total Costs Incurred $1,247 $3,149 $1,828 $6,224 $4,597 $2,348 $684 $1,898 $9,527 $15,751 $832 $71
Year Ended Dec. 31, 2006
Exploration
Wells $– $493 $22 $515 $151 $121 $20 $246 $538 $1,053 $25 $–
Geological and geophysical – 96 8 104 180 53 12 92 337 441 – –
Rentals and other – 116 16 132 48 140 58 50 296 428 – –
Total exploration – 705 46 751 379 314 90 388 1,171 1,922 25 –
Property acquisitions2
Proved 6 152 – 158 1 10 – 15 26 184 – 581
Unproved 1 47 10 58 – 1 – 135 136 194 – –
Total property acquisitions 7 199 10 216 1 11 – 150 162 378 – 581
Development3 686 1,632 868 3,186 2,890 1,788 460 1,019 6,157 9,343 671 25
Total Costs Incurred $693 $2,536 $924 $4,153 $3,270 $2,113 $550 $1,557 $7,490 $11,643 $696 $606
Year Ended Dec. 31, 2005
Exploration
Wells $– $452 $24 $476 $105 $38 $9 $201 $353 $829 $– $–
Geological and geophysical – 67 – 67 96 28 10 68 202 269 – –
Rentals and other – 93 8 101 24 58 12 72 166 267 – –
Total exploration – 612 32 644 225 124 31 341 721 1,365 – –
Property acquisitions2
Proved – Unocal – 1,608 2,388 3,996 30 6,609 637 1,790 9,066 13,062 – –
Proved – Other – 6 10 16 2 2 – 12 16 32 – –
Unproved – Unocal – 819 295 1,114 11 2,209 821 38 3,079 4,193 – –
Unproved – Other – 17 6 23 67 – – 28 95 118 – –
Total property acquisitions – 2,450 2,699 5,149 110 8,820 1,458 1,868 12,256 17,405 – –
Development3 507 608 601 1,788 1,892 1,088 382 726 4,088 5,876 767 43
Total Costs Incurred $507 $3,742 $3,332 $7,581 $2,227 $10,032 $1,871 $2,935 $17,065 $24,646 $767 $43

Table II — Capitalized Costs Related to Oil and Gas Producing Activities

Consolidated Companies
United States International Affiliated Companies
Millions of dollars Calif. Gulf of Mexico Other Total U.S. Africa Asia-Pacific Indonesia Other Total
Int'l.		 Total TCO Other
At Dec. 31, 2007
Unproved properties $805 $892 $353 $2,050 $314 $2,639 $630 $1,015 $4,598 $6,648 $112 $–
Proved properties and related producing assets 11,260 19,110 13,718 44,088 11,894 17,321 7,705 11,360 48,280 92,368 4,247 858
Support equipment 201 206 230 637 850 284 1,123 439 2,696 3,333 758 –
Deferred exploratory wells – 406 7 413 368 293 148 438 1,247 1,660 – –
Other uncompleted projects 308 3,128 573 4,009 6,430 2,049 593 1,421 10,493 14,502 1,633 55
Gross Cap. Costs 12,574 23,742 14,881 51,197 19,856 22,586 10,199 14,673 67,314 118,511 6,750 913
Unproved properties valuation 741 57 35 833 201 221 39 427 888 1,721 23 –
Proved producing properties – Depreciation and depletion 7,383 15,074 7,640 30,097 5,427 6,912 5,592 7,062 24,993 55,090 644 167
Support equipment depreciation 133 92 124 349 464 144 571 261 1,440 1,789 267 –
Accumulated provisions 8,257 15,223 7,799 31,279 6,092 7,277 6,202 7,750 27,321 58,600 934 167
Net Capitalized Costs $4,317 $8,519 $7,082 $19,918 $13,764 $15,309 $3,997 $6,923 $39,993 $59,911 $5,816 $746
At Dec. 31, 2006
Unproved properties $770 $1,007 $370 $2,147 $342 $2,373 $707 $1,082 $4,504 $6,651 $112 $–
Proved properties and related producing assets 9,960 18,464 12,284 40,708 9,943 15,486 7,110 10,461 43,000 83,708 2,701 1,096
Support equipment 189 212 226 627 745 240 1,093 364 2,442 3,069 611 –
Deferred exploratory wells – 343 7 350 231 217 149 292 889 1,239 – –
Other uncompleted projects 370 2,188 – 2,558 4,299 1,546 493 917 7,255 9,813 2,493 40
Gross Cap. Costs 11,289 22,214 12,887 46,390 15,560 19,862 9,552 13,116 58,090 104,480 5,917 1,136
Unproved properties valuation 738 52 29 819 189 74 14 337 614 1,433 22 –
Proved producing properties – Depreciation and depletion 7,082 14,468 6,880 28,430 4,794 5,273 4,971 6,087 21,125 49,555 541 109
Support equipment depreciation 125 111 130 366 400 102 522 238 1,262 1,628 242 –
Accumulated provisions 7,945 14,631 7,039 29,615 5,383 5,449 5,507 6,662 23,001 52,616 805 109
Net Capitalized Costs $3,344 $7,583 $5,848 $16,775 $10,177 $14,413 $4,045 $6,454 $35,089 $51,864 $5,112 $1,027
At Dec. 31, 2005
Unproved properties $769 $1,077 $397 $2,243 $407 $2,287 $645 $983 $4,322 $6,565 $108 $–
Proved properties and related producing assets 9,546 18,283 11,467 39,296 8,404 14,928 6,613 9,627 39,572 78,868 2,264 1,213
Support equipment 204 193 230 627 715 426 1,217 356 2,714 3,341 549 –
Deferred exploratory wells – 284 5 289 245 154 173 248 820 1,109 – –
Other uncompleted projects 149 782 209 1,140 2,878 790 427 946 5,041 6,181 2,332 –
Gross Cap. Costs 10,668 20,619 12,308 43,595 12,649 18,585 9,075 12,160 52,469 96,064 5,253 1,213
Unproved properties valuation 736 90 22 848 162 69 – 318 549 1,397 17 –
Proved producing properties – Depreciation and depletion 6,818 14,067 6,049 26,934 4,266 4,016 4,105 5,720 18,107 45,041 460 90
Support equipment depreciation 140 119 149 408 317 88 680 222 1,307 1,715 213 –
Accumulated provisions 7,694 14,276 6,220 28,190 4,745 4,173 4,785 6,260 19,963 48,153 690 90
Net Capitalized Costs $2,974 $6,343 $6,088 $15,405 $7,904 $14,412 $4,290 $5,900 $32,506 $47,911 $4,563 $1,123

Table III — Results of Operations for Oil and Gas Producing Activities 1

The company's results of operations from oil and gas producing activities for the years 2007, 2006 and 2005 are shown in the following table. Net income from exploration and production activities as reported on Segment Earnings reflects income taxes computed on an effective rate basis. In accordance with FAS 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on Segment Earnings.

Consolidated Companies
United States International Affiliated Companies
Millions of dollars Calif. Gulf of Mexico Other Total U.S. Africa Asia-Pacific Indonesia Other Total
Int'l.		 Total TCO Other
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Includes $10 costs incurred prior to assignment of proved reserves in 2007.
3 Represents accretion of ARO liability. Refer to Note 23, "Asset Retirement Obligations."
4 Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements.
Year Ended Dec. 31, 2007
Revenues from net production
Sales $202 $1,555 $2,476 $4,233 $1,810 $6,192 $1,045 $3,012 $12,059 $16,292 $3,327 $1,290
Transfers 4,671 2,630 2,707 10,008 6,778 4,440 2,590 2,744 16,552 26,560 – –
Total 4,873 4,185 5,183 14,241 8,588 10,632 3,635 5,756 28,611 42,852 3,327 1,290
Production expenses excluding taxes2 (1,063) (936) (1,400) (3,399) (892) (953) (892) (828) (3,565) (6,964) (248) (92)
Taxes other than on income (91) (53) (378) (522) (49) (292) (2) (58) (401) (923) (31) (163)
Proved producing properties: Depreciation and depletion (300) (1,143) (833) (2,276) (646) (1,668) (623) (980) (3,917) (6,193) (127) (94)
Accretion expense3 (92) 1 (167) (258) (33) (36) (21) (27) (117) (375) (1) (2)
Exploration expenses – (486) (25) (511) (267) (225) (61) (259) (812) (1,323) – –
Unproved properties valuation (3) (102) (27) (132) (12) (150) (30) (120) (312) (444) – –
Other income (expense)4 3 2 31 36 (447) (302) (197) (722) (1,668) (1,632) 18 7
Results before income taxes 3,327 1,468 2,384 7,179 6,242 7,006 1,809 2,762 17,819 24,998 2,938 946
Income tax expense (1,204) (531) (864) (2,599) (4,907) (3,456) (841) (1,624) (10,828) (13,427) (887) (462)
Results of Producing Operations $2,123 $937 $1,520 $4,580 $1,335 $3,550 $968 $1,138 $6,991 $11,571 $2,051 $484
Year Ended Dec. 31, 2006
Revenues from net production
Sales $308 $1,845 $2,976 $5,129 $2,377 $4,938 $1,001 $2,814 $11,130 $16,259 $2,861 $598
Transfers 4,072 2,317 2,046 8,435 5,264 4,084 2,211 2,848 14,407 22,842 – –
Total 4,380 4,162 5,022 13,564 7,641 9,022 3,212 5,662 25,537 39,101 2,861 598
Production expenses excluding taxes (889) (765) (1,057) (2,711) (640) (740) (728) (664) (2,772) (5,483) (202) (42)
Taxes other than on income (84) (57) (442) (583) (57) (231) (1) (60) (349) (932) (28) (6)
Proved producing properties: Depreciation and depletion (275) (1,096) (763) (2,134) (579) (1,475) (666) (703) (3,423) (5,557) (114) (33)
Accretion expense3 (11) (80) (39) (130) (26) (30) (23) (49) (128) (258) (1) –
Exploration expenses – (407) (24) (431) (296) (209) (110) (318) (933) (1,364) (25) –
Unproved properties valuation (3) (73) (8) (84) (28) (15) (14) (27) (84) (168) – –
Other income (expense)4 1 (732) 254 (477) (435) (475) 50 385 (475) (952) 8 (50)
Results before income taxes 3,119 952 2,943 7,014 5,580 5,847 1,720 4,226 17,373 24,387 2,499 467
Income tax expense (1,169) (357) (1,103) (2,629) (4,740) (3,224) (793) (2,151) (10,908) (13,537) (750) (174)
Results of Producing Operations $1,950 $595 $1,840 $4,385 $840 $2,623 $927 $2,075 $6,465 $10,850 $1,749 $293
Year Ended Dec. 31, 2005
Revenues from net production
Sales $337 $1,576 $3,174 $5,087 $2,142 $2,941 $539 $2,668 $8,290 $13,377 $2,307 $666
Transfers 3,497 2,127 1,395 7,019 3,615 3,179 1,986 2,607 11,387 18,406 – –
Total 3,834 3,703 4,569 12,106 5,757 6,120 2,525 5,275 19,677 31,783 2,307 666
Production expenses excluding taxes (916) (638) (777) (2,331) (558) (570) (660) (596) (2,384) (4,715) (152) (82)
Taxes other than on income (65) (41) (384) (490) (48) (189) (1) (195) (433) (923) (27) –
Proved producing properties: Depreciation and depletion (253) (936) (520) (1,709) (414) (852) (550) (672) (2,488) (4,197) (83) (46)
Accretion expense3 (13) (35) (46) (94) (22) (20) (15) (25) (82) (176) (1) –
Exploration expenses – (307) (13) (320) (117) (90) (26) (190) (423) (743) – –
Unproved properties valuation (3) (32) (4) (39) (50) (8) – (24) (82) (121) – –
Other income (expense)4 2 (354) (140) (492) (243) (182) 182 280 37 (455) (9) 8
Results before income taxes 2,586 1,360 2,685 6,631 4,305 4,209 1,455 3,853 13,822 20,453 2,035 546
Income tax expense (913) (482) (953) (2,348) (3,430) (2,264) (644) (1,938) (8,276) (10,624) (611) (186)
Results of Producing Operations $1,673 $878 $1,732 $4,283 $875 $1,945 $811 $1,915 $5,546 $9,829 $1,424 $360

Table IV — Results of Operations for Oil and Gas Producing Activities — Unit Prices and Costs 1,2

Consolidated Companies
United States International Affiliated Companies
Calif. Gulf of Mexico Other Total U.S. Africa Asia-Pacific Indonesia Other Total
Int'l.		 Total TCO Other
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
Year Ended Dec. 31, 2007
Average sales prices
Liquids, per barrel $62.61 $65.07 $62.35 $63.16 $69.90 $64.20 $61.05 $62.97 $65.40 $64.71 $62.47 $51.98
Natural gas, per thousand cubic feet 5.77 7.01 5.65 6.12 – 3.60 7.61 4.13 4.02 4.79 0.89 0.44
Average production costs, per barrel 13.23 12.32 12.62 12.72 7.26 3.96 14.28 6.96 6.54 8.58 3.98 3.56
Year Ended Dec. 31, 2006
Average sales prices
Liquids, per barrel $55.20 $60.35 $55.80 $56.66 $61.53 $57.05 $52.23 $57.31 $57.92 $57.53 $56.80 $37.26
Natural gas, per thousand cubic feet 6.08 7.20 5.73 6.29 0.06 3.44 7.12 4.03 3.88 4.85 0.77 0.36
Average production costs, per barrel 10.94 9.59 9.26 9.85 5.13 3.36 11.44 5.23 5.17 6.76 3.31 2.51
Year Ended Dec. 31, 2005
Average sales prices
Liquids, per barrel $45.24 $48.80 $48.29 $46.97 $50.54 $45.88 $44.40 $48.61 $47.83 $47.56 $45.59 $45.89
Natural gas, per thousand cubic feet 6.94 8.43 6.90 7.43 0.04 3.59 5.74 3.31 3.48 5.18 0.61 0.26
Average production costs, per barrel 10.74 8.55 7.57 8.88 4.72 3.38 11.28 4.32 4.93 6.32 2.45 5.53

Table V — Reserve Quantity Information

Reserves Governance

The company has adopted a comprehensive reserves and resource classification system modeled after a system developed and approved by the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The system classifies recoverable hydrocarbons into six categories based on their status at the time of reporting — three deemed commercial and three noncommercial. Within the commercial classification are proved reserves and two categories of unproved: probable and possible. The noncommercial categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC and company standards.

Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.

Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the corporate reserves manager, who is a member of a corporate department that reports directly to the executive vice president responsible for the company's worldwide exploration and production activities. All of the RAC members are knowledgeable in SEC guidelines for proved reserves classification. The RAC coordinates its activities through two operating company-level reserves managers. These two reserves managers are not members of the RAC so as to preserve the corporate-level independence.

The RAC has the following primary responsibilities: provide independent reviews of the business units' recommended reserve changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology; and maintain the Corporate Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

During the year, the RAC is represented in meetings with each of the company's upstream business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company's Strategy and Planning Committee and the Executive Committee, whose members include the Chief Executive Officer and the Chief Financial Officer. The company's annual reserve activity is also reviewed with the Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.

RAC subteams also conduct in-depth reviews during the year of many of the fields that have the largest proved reserves quantities. These reviews include an examination of the proved-reserve records and documentation of their alignment with the Corporate Reserves Manual.

Reserve Quantities

At December 31, 2007, oil-equivalent reserves for the company's consolidated operations were 7.9 billion barrels. (Refer to the term "Reserves" on Glossary of Terms for the definition of oil-equivalent reserves.) Approximately 28 percent of the total reserves were in the United States. For the company's interests in equity affiliates, oil-equivalent reserves were 2.9 billion barrels, 84 percent of which were associated with the company's 50 percent ownership in TCO.

Aside from the TCO operations, no single property accounted for more than 5 percent of the company's total oil-equivalent proved reserves. Fewer than 20 other individual properties in the company's portfolio of assets each contained between 1 percent and 5 percent of the company's oil-equivalent proved reserves, which in the aggregate accounted for about 37 percent of the company's proved reserves total. These properties were geographically dispersed, located in the United States, South America, West Africa and the Asia-Pacific region.

In the United States, total oil-equivalent reserves at year-end 2007 were 2.2 billion barrels. Of this amount, 41 percent, 21 percent and 38 percent were located in California, the Gulf of Mexico and other U.S. areas, respectively.

In California, liquids reserves represented 94 percent of the total, with most classified as heavy oil. Because of heavy oil's high viscosity and the need to employ enhanced recovery methods, the producing operations are capital intensive in nature. Most of the company's heavy-oil fields in California employ a continuous steamflooding process.

In the Gulf of Mexico region, liquids represented approximately 66 percent of total oil-equivalent reserves. Production operations are mostly offshore and, as a result, are also capital intensive. Costs include investments in wells, production platforms and other facilities, such as gathering lines and storage facilities.

In other U.S. areas, the reserves were split about equally between liquids and natural gas. For production of crude oil, some fields utilize enhanced recovery methods, including waterflood and CO2 injection.

The pattern of net reserve changes shown in the following tables, for the three years ending December 31, 2007, is not necessarily indicative of future trends. Apart from acquisitions, the company's ability to add proved reserves is affected by, among other things, events and circumstances that are outside the company's control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest.

The company's estimated net proved oil and natural gas reserves and changes thereto for the years 2005, 2006 and 2007 are shown in the table below and in the table entitled Net Proved Reserves of Natural Gas.

Net Proved Reserves of Crude Oil, Condensate and Natural Gas Liquids
Consolidated Companies
United States International Affiliated Companies
Millions of barrels Calif. Gulf of Mexico Other Total U.S. Africa Asia-Pacific Indonesia Other Total
Int'l.		 Total TCO Other
1 Includes reserves acquired through nonmonetary transactions.
2 Includes reserves disposed of through nonmonetary transactions.
3 Includes year-end reserve quantities related to production-sharing contracts (PSC) (refer to Glossary of Terms for the definition of a PSC). PSC-related reserve quantities are 26 percent, 30 percent and 29 percent for consolidated companies for 2007, 2006 and 2005, respectively.
4 Net reserve changes (excluding production) in 2007 consist of 97 million barrels of developed reserves and (162) million barrels of undeveloped reserves for consolidated companies and 299 million barrels of developed reserves and (312) million barrels of undeveloped reserves for affiliated companies.
5 During 2007, the percentages of undeveloped reserves at December 31, 2006, transferred to developed reserves were 8 percent and 24 percent for consolidated companies and affiliated companies, respectively.

Information on Canadian Oil Sands Net Proved Reserves Not Included Above:

In addition to conventional liquids and natural gas proved reserves, Chevron has significant interests in proved oil sands reserves in Canada associated with the Athabasca project. For internal management purposes, Chevron views these reserves and their development as an integral part of total upstream operations. However, SEC regulations define these reserves as mining-related and not a part of conventional oil and gas reserves. Net proved oil sands reserves were 436 million barrels as of December 31, 2007. The oil sands reserves are not considered in the standardized measure of discounted future net cash flows for conventional oil and gas reserves, which is found on Table VI.
Reserves at Jan. 1, 2005 1,011 294 432 1,737 1,833 676 698 567 3,774 5,511 1,994 468
Changes attributable to:
Revisions (23) (6) (11) (40) (29) (56) (108) (6) (199) (239) (5) (19)
Improved recovery 57 – 4 61 67 4 42 29 142 203 – –
Extensions and discoveries – 37 7 44 53 21 1 65 140 184 – –
Purchases1 – 49 147 196 4 287 20 65 376 572 – –
Sales2 (1) – (1) (2) – – – (58) (58) (60) – –
Production (79) (41) (45) (165) (114) (103) (74) (89) (380) (545) (50) (14)
Reserves at Dec. 31, 20053 965 333 533 1,831 1,814 829 579 573 3,795 5,626 1,939 435
Changes attributable to:
Revisions (14) 7 7 – (49) 72 61 (45) 39 39 60 24
Improved recovery 49 – 3 52 13 1 6 11 31 83 – –
Extensions and discoveries – 25 8 33 30 6 2 36 74 107 – –
Purchases1 2 2 – 4 15 – – 2 17 21 – 119
Sales2 – – – – – – – (15) (15) (15) – –
Production (76) (42) (51) (169) (125) (123) (72) (78) (398) (567) (49) (16)
Reserves at Dec. 31, 20063 926 325 500 1,751 1,698 785 576 484 3,543 5,294 1,950 562
Changes attributable to:
Revisions 1 (1) (5) (5) (89) 7 (66) 7 (141) (146) 92 11
Improved recovery 6 – 3 9 7 3 1 – 11 20 – –
Extensions and discoveries 1 25 10 36 6 1 – 17 24 60 – –
Purchases1 1 9 – 10 – – – – – 10 – 316
Sales2 – (8) (1) (9) – – – – – (9) – (432)
Production (75) (43) (50) (168) (122) (128) (72) (74) (396) (564) (53) (24)
Reserves at Dec. 31, 20073,4 860 307 457 1,624 1,500 668 439 434 3,041 4,665 1,989 433
Developed Reserves5
At Jan. 1, 2005 832 192 386 1,410 990 543 490 469 2,492 3,902 1,510 188
At Dec. 31, 2005 809 177 474 1,460 945 534 439 416 2,334 3,794 1,611 196
At Dec. 31, 2006 749 163 443 1,355 893 530 426 349 2,198 3,553 1,003 311
At Dec. 31, 2007 701 136 401 1,238 758 422 363 305 1,848 3,086 1,273 263

Noteworthy amounts in the categories of liquids proved-reserve changes for 2005 through 2007 are discussed below:

Revisions

In 2005, net revisions reduced reserves by 239 million and 24 million barrels for worldwide consolidated companies and equity affiliates, respectively. For consolidated companies, the net decrease was 199 million barrels in the international areas and 40 million barrels in the United States. The largest downward net revisions internationally were 108 million barrels in Indonesia and 53 million barrels in Kazakhstan, due primarily to the effect of higher year-end prices on the calculation of reserves associated with production-sharing and variable-royalty contracts. In the United States, the 40 million-barrel reduction was across many fields in each of the geographic sections. Most of the downward revision for affiliated companies was a 19 million-barrel reduction in Hamaca, attributable to revised government royalty provisions. For TCO, the downward effect of higher year-end prices was partially offset by increased reservoir performance.

In 2006, net revisions increased reserves by 39 million and 84 million barrels for worldwide consolidated companies and equity affiliates, respectively. International consolidated companies accounted for the net increase of 39 million barrels. The largest upward net revisions were 61 million barrels in Indonesia and 27 million barrels in Thailand. In Indonesia, the increase was the result of infill drilling and improved steamflood performance. The upward revision in Thailand reflected additional drilling and development activity during the year. These upward revisions were partially offset by reductions in reservoir performance in Nigeria and the United Kingdom, which decreased reserves by 43 million barrels and by 32 million barrels, respectively. Most of the upward revision for affiliated companies was related to a 60 million-barrel increase in TCO as a result of improved reservoir performance.

In 2007, net revisions decreased reserves by 146 million barrels for worldwide consolidated companies and increased reserves by 103 million barrels for equity affiliates. For consolidated companies, the largest downward net revisions were 89 million barrels in Africa and 66 million barrels in Indonesia. In Africa, the decrease was mainly based on field performance data for fields in Nigeria and the effect of higher year-end prices in Angola and the Republic of the Congo. In Indonesia, the decline also reflected the impact of higher year-end prices. Higher prices also resulted in downward revisions in Karachaganak and Azerbaijan. For equity affiliates, most of the upward revision was related to a 92 million-barrel increase for the Tengiz Field in TCO and an 11 million-barrel increase for Petroboscan in Venezuela, both as a result of improved reservoir performance. At TCO, the upward revision was tempered by the negative impact of higher year-end prices.

Improved Recovery

In 2005, improved recovery increased liquids volumes worldwide by 203 million barrels for consolidated companies. International areas accounted for 142 million barrels of the increase. Indonesia added 42 million barrels due to improved performance. Reserve additions of 67 million barrels in Africa occurred primarily in Angola and resulted from infill drilling, wells workovers and secondary recovery from gas injection. Additions of 29 million barrels in the "Other" international area were mainly attributable to improved waterflood performance offshore eastern Canada. An increase of 61 million barrels occurred in the United States, primarily in California due to improved performance on a large heavy oil field under thermal recovery.

In 2006, improved recovery increased liquids volumes worldwide by 83 million barrels for consolidated companies. Reserves in the United States increased 52 million barrels, with California representing 49 million barrels of the total increase due to steamflood expansion and revised modeling activities. Internationally, improved recovery increased reserves by 31 million barrels, with no single country accounting for an increase of more than 10 million barrels.

In 2007, improved recovery increased liquids volumes by 20 million barrels worldwide. No addition was individually significant.

Extensions and Discoveries

In 2005, extensions and discoveries increased liquids volumes worldwide by 184 million barrels for consolidated companies. The largest increase was 49 million barrels in Nigeria, reflecting new development drilling, including in the Agbami Field, among others. New field developments in Brazil contributed another 41 million barrels of discoveries. In the United States, the 44 million-barrel addition was associated mainly with the initial booking of reserves for the Blind Faith Field in the deepwater Gulf of Mexico.

In 2006, extensions and discoveries increased liquids volumes worldwide by 107 million barrels for consolidated companies. Reserves in Nigeria increased by 27 million barrels due in part to the initial booking of reserves for the Aparo Field. Additional drilling activities contributed 19 million barrels in the United Kingdom and 14 million barrels in Argentina. In the United States, the Gulf of Mexico added 25 million barrels, mainly the result of the initial booking of the Great White Field in the deepwater Perdido Fold Belt area.

In 2007, extensions and discoveries increased liquids volumes by 60 million barrels worldwide. The largest additions were 25 million barrels in the U.S. Gulf of Mexico, mainly for the deepwater Tahiti and Mad Dog fields.

Purchases

In 2005, the acquisition of 572 million barrels of liquids related solely to the acquisition of Unocal in August. About three-fourths of the 376 million barrels acquired in the international areas were represented by volumes in Azerbaijan and Thailand. Most volumes acquired in the United States were in Texas and Alaska.

In 2006, acquisitions increased liquids volumes worldwide by 21 million barrels for consolidated companies and 119 million barrels for equity affiliates. For consolidated companies, the amount was mainly the result of new agreements in Nigeria, which added 13 million barrels of reserves. The other-equity-affiliates quantity reflects the result of the conversion of Boscan and LL-652 operations to joint stock companies in Venezuela.

In 2007, acquisitions of 316 million barrels for equity affiliates related to the formation of a new Hamaca equity affiliate in Venezuela.

Sales

In 2005, sales of 58 million barrels in the "Other" international area related to the disposition of the former Unocal operations onshore in Canada.

In 2006, sales decreased reserves by 15 million barrels due to the conversion of the LL-652 risked service agreement to a joint stock company in Venezuela.

In 2007, affiliated company sales of 432 million barrels related to the dissolution of a Hamaca equity affiliate in Venezuela.

Net Proved Reserves of Natural Gas
Consolidated Companies
United States International Affiliated Companies
Billions of cubic feet Calif. Gulf of Mexico Other Total U.S. Africa Asia-Pacific Indonesia Other Total
Int'l.		 Total TCO Other
1 Includes reserves acquired through nonmonetary transactions.
2 Includes reserves disposed of through nonmonetary transactions.
3 Includes year-end reserve quantities related to production-sharing contracts (PSC) (refer to Glossary of Terms for the definition of a PSC). PSC-related reserve quantities are 37 percent, 47 percent and 44 percent for consolidated companies for 2007, 2006 and 2005, respectively.
4 Net reserve changes (excluding production) in 2007 consist of 1,548 billion cubic feet of developed reserves and (569) billion cubic feet of undeveloped reserves for consolidated companies and 403 billion cubic feet of developed reserves and (294) billion cubic feet of undeveloped reserves for affiliated companies.
5 During 2007, the percentages of undeveloped reserves at December 31, 2006, transferred to developed reserves were 10 percent and 27 percent for consolidated companies and affiliated companies, respectively.
Reserves at Jan. 1, 2005 314 1,064 2,326 3,704 2,979 5,405 502 3,538 12,424 16,128 3,413 134
Changes attributable to:
Revisions 21 (15) (15) (9) 211 (428) (31) 243 (5) (14) (547) 49
Improved recovery 8 – – 8 13 – – 31 44 52 – –
Extensions and discoveries – 68 99 167 25 118 5 55 203 370 – –
Purchases1 – 269 899 1,168 5 3,962 247 274 4,488 5,656 – –
Sales2 – – (6) (6) – – – (248) (248) (254) – –
Production (39) (215) (350) (604) (42) (434) (77) (315) (868) (1,472) (79) (2)
Reserves at Dec. 31, 20053 304 1,171 2,953 4,428 3,191 8,623 646 3,578 16,038 20,466 2,787 181
Changes attributable to:
Revisions 32 40 (102) (30) 34 400 38 39 511 481 26 –
Improved recovery 5 – – 5 3 – – 5 8 13 – –
Extensions and discoveries – 111 157 268 11 510 – 10 531 799 – –
Purchases1 6 13 – 19 – 16 – – 16 35 – 54
Sales2 – – (1) (1) – – – (148) (148) (149) – –
Production (37) (241) (383) (661) (33) (629) (110) (302) (1,074) (1,735) (70) (4)
Reserves at Dec. 31, 20063 310 1,094 2,624 4,028 3,206 8,920 574 3,182 15,882 19,910 2,743 231
Changes attributable to:
Revisions 40 39 130 209 (141) 149 12 166 186 395 75 (2)
Improved recovery – – – – – – – 1 1 1 – –
Extensions and discoveries – 40 46 86 11 392 – 29 432 518 – –
Purchases1 2 19 29 50 – 91 – – 91 141 – 211
Sales2 – (39) (37) (76) – – – – – (76) – (175)
Production (35) (210) (375) (620) (27) (725) (101) (279) (1,132) (1,752) (70) (10)
Reserves at Dec. 31, 20073,4 317 943 2,417 3,677 3,049 8,827 485 3,099 15,460 19,137 2,748 255
Developed Reserves5
At Jan. 1, 2005 252 937 2,191 3,380 1,108 3,701 271 2,273 7,353 10,733 2,584 63
At Dec. 31, 2005 251 977 2,794 4,022 1,346 4,819 449 2,453 9,067 13,089 2,314 85
At Dec. 31, 2006 250 873 2,434 3,557 1,306 4,751 377 1,912 8,346 11,903 1,412 144
At Dec. 31, 2007 261 727 2,238 3,226 1,151 5,081 326 1,915 8,473 11,699 1,762 117

Noteworthy amounts in the categories of natural gas proved-reserve changes for 2005 through 2007 are discussed below:

Revisions

In 2005, reserves were revised downward by 14 billion cubic feet (BCF) for consolidated companies and 498 BCF for equity affiliates. For consolidated companies, negative revisions were 428 BCF in the Asia-Pacific region. Most of the decrease was attributable to one field in Kazakhstan, due mainly to the effects of higher year-end prices on variable-royalty provisions of the production-sharing contract. Reserves additions for consolidated companies totaled 211 BCF and 243 BCF in Africa and "Other," respectively. The majority of the African region changes were in Angola, due to a revised forecast of fuel gas usage, and in Nigeria, from improved reservoir performance. The availability of third-party compression in Colombia accounted for most of the increase in the "Other" region. Revisions in the United States decreased reserves by 9 BCF, as nominal increases in the San Joaquin Valley were more than offset by decreases in the Gulf of Mexico and "Other" region. For the TCO affiliate in Kazakhstan, a reduction of 547 BCF reflects the updated forecast of future royalties payable and year-end price effects, partially offset by volumes added as a result of an updated assessment of reservoir performance.

In 2006, revisions accounted for a net increase of 481 BCF for consolidated companies and 26 BCF for affiliates. For consolidated companies, net increases of 511 BCF internationally were partially offset by a 30 BCF downward revision in the United States. Drilling and development activities added 337 BCF of reserves in Thailand, while Kazakhstan added 200 BCF, largely due to development activity. Trinidad and Tobago increased 185 BCF, attributable to improved reservoir performance and a new contract for sales of natural gas. These additions were partially offset by downward revisions of 224 BCF in the United Kingdom and 130 BCF in Australia due to drilling results and reservoir performance. U.S. "Other" had a downward revision of 102 BCF due to reservoir performance, which was partially offset by upward revisions of 72 BCF in the Gulf of Mexico and California related to reservoir performance and development drilling. TCO had an upward revision of 26 BCF associated with additional development activity and updated reservoir performance.

In 2007, revisions increased reserves for consolidated companies by a net 395 BCF and increased reserves for affiliated companies by a net 73 BCF. For consolidated companies, net increases were 209 BCF in the United States and 186 BCF internationally. Improved reservoir performance for many fields in the United States contributed 130 BCF in the "Other" region, 40 BCF in California and 39 BCF in the Gulf of Mexico. Drilling activities added 360 BCF in Thailand and improved reservoir performance added 188 BCF in Trinidad and Tobago. These additions were partially offset by downward revisions of 185 BCF in Australia due to drilling results and 136 BCF in Nigeria due to field performance. Negative revisions due to the impact of higher prices were recorded in Azerbaijan and Kazakhstan. TCO had an upward revision of 75 BCF associated with improved reservoir performance and development activities. This upward revision was net of a negative impact due to higher year-end prices.

Extensions and Discoveries

In 2005, consolidated companies increased reserves by 370 BCF, including 167 BCF in the United States and 118 BCF in the Asia-Pacific region. In the United States, 99 BCF was added in the "Other" region and 68 BCF in the Gulf of Mexico, primarily due to drilling activities. The addition in Asia-Pacific resulted primarily from increased drilling in Kazakhstan.

In 2006, extensions and discoveries accounted for an increase of 799 BCF for consolidated companies, reflecting a 531 BCF increase outside the United States and a U.S. increase of 268 BCF. Bangladesh added 451 BCF, the result of development activity and field extensions, and Thailand added 59 BCF, the result of drilling activities. U.S. "Other" contributed 157 BCF, approximately half of which was related to South Texas and the Piceance Basin, and the Gulf of Mexico added 111 BCF, partly due to the initial booking of reserves at the Great White Field in the deepwater Perdido Fold Belt area.

In 2007, extensions and discoveries accounted for an increase of 518 BCF worldwide. The largest addition was 330 BCF in Bangladesh, the result of drilling activities. Other additions were not individually significant.

Purchases

In 2005, all except 7 BCF of the 5,656 BCF total purchases were associated with the Unocal acquisition. International reserve acquisitions were 4,488 BCF, with Thailand accounting for about half the volumes. Other significant volumes were added in Bangladesh and Myanmar.

In 2006, purchases of natural gas reserves were 35 BCF for consolidated companies, about evenly divided between the company's United States and international operations. Affiliated companies added 54 BCF of reserves, the result of conversion of an operating service agreement to a joint stock company in Venezuela.

In 2007, purchases of natural gas reserves were 141 BCF for consolidated companies, which include the acquisition of an additional interest in the Bibiyana Field in Bangladesh. Affiliated company purchases of 211 BCF related to the formation of a new Hamaca equity affiliate in Venezuela and an initial booking related to the Angola LNG project.

Sales

In 2005, sales of 248 BCF in the "Other" international region related to the disposition of former-Unocal's onshore properties in Canada.

In 2006, sales for consolidated companies totaled 149 BCF, mostly associated with the conversion of a risked service agreement to a joint stock company in Venezuela.

In 2007, sales were 76 BCF and 175 BCF for consolidated companies and equity affiliates, respectively. The affiliated company sales related to the dissolution of a Hamaca equity affiliate in Venezuela.

Table VI — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FAS 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions, and include estimated costs for asset retirement obligations. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10 percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.

The information provided does not represent management's estimate of the company's expected future cash flows or value of proved oil and gas reserves. Estimates of proved-reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under FAS 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company's future cash flows or value of its oil and gas reserves. In the following table, "Standardized Measure Net Cash Flows" refers to the standardized measure of discounted future net cash flows.

Consolidated Companies
United States International Affiliated Companies
Millions of dollars Calif. Gulf of Mexico Other Total U.S. Africa Asia-Pacific Indonesia Other Total
Int'l.		 Total TCO Other
At December 31, 2007
Future cash inflows from production $75,201 $34,162 $52,775 $162,138 $132,450 $93,046 $35,020 $45,566 $306,082 $468,220 $159,078 $29,845
Future production costs (17,888) (7,193) (16,780) (41,861) (15,707) (16,022) (18,270) (11,990) (61,989) (103,850) (10,408) (1,529)
Future devel. costs (3,491) (3,011) (1,578) (8,080) (11,516) (8,263) (4,012) (3,468) (27,259) (35,339) (8,580) (1,175)
Future income taxes (19,112) (8,507) (12,221) (39,840) (74,172) (26,838) (5,796) (15,524) (122,330) (162,170) (39,575) (13,600)
Undiscounted future net cash flows 34,710 15,451 22,196 72,357 31,055 41,923 6,942 14,584 94,504 166,861 100,515 13,541
10 percent midyear annual discount for timing of estimated cash flows (17,204) (4,438) (9,491) (31,133) (14,171) (17,117) (2,702) (4,689) (38,679) (69,812) (64,519) (7,779)
Standardized Measure Net Cash Flows $17,506 $11,013 $12,705 $41,224 $16,884 $24,806 $4,240 $9,895 $55,825 $97,049 $35,996 $5,762
At December 31, 2006
Future cash inflows from production $48,828 $23,768 $38,727 $111,323 $97,571 $70,288 $30,538 $36,272 $234,669 $345,992 $104,069 $20,644
Future production costs (14,791) (6,750) (12,845) (34,386) (12,523) (13,398) (16,281) (10,777) (52,979) (87,365) (7,796) (2,348)
Future devel. costs (3,999) (2,947) (1,399) (8,345) (9,648) (6,963) (2,284) (3,082) (21,977) (30,322) (7,026) (1,732)
Future income taxes (10,171) (4,764) (8,290) (23,225) (53,214) (20,633) (5,448) (11,164) (90,459) (113,684) (25,212) (8,282)
Undiscounted future net cash flows 19,867 9,307 16,193 45,367 22,186 29,294 6,525 11,249 69,254 114,621 64,035 8,282
10 percent midyear annual discount for timing of estimated cash flows (9,779) (3,256) (7,210) (20,245) (10,065) (12,457) (2,426) (3,608) (28,556) (48,801) (40,597) (5,185)
Standardized Measure Net Cash Flows $10,088 $6,051 $8,983 $25,122 $12,121 $16,837 $4,099 $7,641 $40,698 $65,820 $23,438 $3,097
At December 31, 2005
Future cash inflows from production $50,771 $29,422 $50,039 $130,232 $101,912 $73,612 $32,538 $44,680 $252,742 $382,974 $97,707 $20,616
Future production costs (15,719) (5,758) (12,767) (34,244) (11,366) (12,459) (18,260) (11,908) (53,993) (88,237) (7,399) (2,101)
Future devel. costs (2,274) (2,467) (873) (5,614) (8,197) (5,840) (1,730) (2,439) (18,206) (23,820) (5,996) (762)
Future income taxes (11,092) (7,173) (12,317) (30,582) (50,894) (21,509) (5,709) (13,917) (92,029) (122,611) (23,818) (6,036)
Undiscounted future net cash flows 21,686 14,024 24,082 59,792 31,455 33,804 6,839 16,416 88,514 148,306 60,494 11,717
10 percent midyear annual discount for timing of estimated cash flows (10,947) (4,520) (10,838) (26,305) (14,881) (14,929) (2,269) (5,635) (37,714) (64,019) (37,674) (7,768)
Standardized Measure Net Cash Flows $10,739 $9,504 $13,244 $33,487 $16,574 $18,875 $4,570 $10,781 $50,800 $84,287 $22,820 $3,949

Table VII — Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

The changes in present values between years, which can be significant, reflect changes in estimated proved-reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with "Revisions of previous quantity estimates."

Consolidated Companies Affiliated Companies
Millions of dollars 2007 2006 2005 2007 2006 2005
Present Value at January 1 $65,820 $84,287 $48,134 $26,535 $26,769 $14,920
Sales and transfers of oil and gas produced net of production costs (34,957) (32,690) (26,145) (4,084) (3,180) (2,712)
Development costs incurred 10,468 8,875 5,504 889 721 810
Purchases of reserves 780 580 25,307 7,711 1,767 –
Sales of reserves (425) (306) (2,006) (7,767) – –
Extensions, discoveries and improved recovery less related costs 3,664 4,067 7,446 – – –
Revisions of previous quantity estimates (7,801) 7,277 (13,564) (1,333) (967) (2,598)
Net changes in prices, development and production costs 74,900 (24,725) 61,370 23,616 (837) 19,205
Accretion of discount 12,196 14,218 8,160 3,745 3,673 2,055
Net change in income tax (27,596) 4,237 (29,919) (7,554) (1,411) (4,911)
Net change for the year 31,229 (18,467) 36,153 15,223 (234) 11,849
Present Value at December 31 $97,049 $65,820 $84,287 $41,758 $26,535 $26,769