Chevron - 10-K annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

þ     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission File Number 1-368-2

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code (925) 842-1000

Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes þ          No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes o          No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes þ          No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):

Large accelerated filerþ                         Accelerated filero                         Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes o          No þ

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter — $115,713,269,274 (As of June 30, 2005)

Number of Shares of Common Stock outstanding as of February 23, 2006 — 2,226,159,801

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2006 Annual Meeting and 2006 Proxy Statement, to be filed pursuant to Rule 14a-6(b)under the Securities Exchange Act of 1934, in connection with the company’s 2006 Annual Meeting of Stockholders (in Part III)

      This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “schedules,” “estimates” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

      Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are unknown or unexpected problems in the resumption of operations affected by Hurricanes Katrina and Rita and other severe weather in the Gulf of Mexico; crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the ability to successfully integrate the operations of Chevron and Unocal Corporation; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction orstart-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities due to war, accidents, political events, civil unrest or severe weather; the potential liability for remedial actions under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental regulations and litigation (including, particularly, regulations and litigation dealing with gasoline composition and characteristics); the potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” in this report. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

      Chevron Corporation,¹a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial and management support to U.S. and foreign subsidiaries that engage in fully integrated petroleum operations, chemicals operations, mining operations of coal and other minerals, power generation and energy services. The company conducts business activities in the United States and approximately 180 other countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipeline, marine vessel, motor equipment and rail car. Chemicals operations include the manufacture and marketing, by affiliates, of commodity petrochemicals for industrial uses, and the manufacture and marketing, by a consolidated subsidiary, of fuel and lubricating oil additives.

      In this report, exploration and production of crude oil, natural gas liquids and natural gas may be referred to as “E&P” or “upstream” activities. Refining, marketing and transportation may be referred to as “RM&T” or “downstream” activities. A list of the company’s major subsidiaries is presented on pages E-4 andE-5 of this Annual Report on Form 10-K. As of December 31, 2005, Chevron had more than 59,000 employees (including about 6,000 service station employees). Approximately 27,000, or 46 percent, of the company’s employees were employed in U.S. operations.

      On August 10, 2005, the company acquired Unocal Corporation (Unocal), an independent oil and gas exploration and production company. This acquisition was accounted for under the rules of Financial Accounting Standards Board (FASB) Statement No. 141, “Business Combinations.”Unocal’s principal upstream operations are in North America and Asia, including the Caspian region. Other activities include ownership interests in proprietary and common carrier pipelines, natural gas storage facilities and mining operations. Further discussion of the Unocal acquisition is contained in Note 2 on pageFS-36 of this Annual Report on Form 10-K.

      Petroleum industry operations and profitability are influenced by many factors, and individual petroleum companies have little control over some of them. Governmental policies, particularly in the areas of taxation, energy and the environment have a significant impact on petroleum activities, regulating where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil and natural gas, petroleum products and petrochemicals are determined by supply and demand for these commodities. The members of the Organization of Petroleum Exporting Countries (OPEC) are typically the world’s swing producers of crude oil, and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and worldwide economies, although weather patterns and taxation relative to other energy sources also play a significant part. Variations in the components of refined products sales due to seasonality are not primary drivers of changes in the company’s overall annual earnings.

      Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. Chevron competes with fully integrated major petroleum companies as well as independent and national petroleum companies for the acquisition of crude oil and natural gas

¹ Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. On May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we” and “us” may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or to all of them taken as a whole, but unless stated otherwise, it does not include “affiliates” of Chevron — i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or investments accounted for by the cost method. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.

leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron also competes with fully integrated major petroleum companies and other independent refining, marketing and transportation entities in the sale or acquisition of various goods or services in many national and international markets.

      Refer to pages FS-2 throughFS-11 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion on the company’s current business environment and outlook.

      Chevron’s primary objective is to create value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. As a foundation for achieving this objective, the company had established the following strategies, which continue into 2006:

      The upstream and downstream activities of the company are widely dispersed geographically, with operations in North America, South America, Europe, Africa, the Middle East, Central and Far East Asia, and Australia. Besides the large upstream and downstream businesses, the company’s other comparatively smaller business segment is chemicals, which is conducted by the company’s 50 percent-owned affiliate — Chevron Phillips Chemical Company LLC (CPChem) — and the wholly owned Chevron Oronite Company (Chevron Oronite). CPChem has operations in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium. Chevron Oronite is a fuel and lubricating-oil additives business that owns and operates facilities in the United States, France, the Netherlands, Singapore, Japan and Brazil and has equity interests in facilities in India and Mexico.

      Chevron also owns an approximate 24 percent equity interest in the common stock of Dynegy Inc. (Dynegy), a provider of electricity to markets and customers throughout the United States. The company holds an additional investment in Dynegy preferred stock. Refer to pageFS-13 for further information relating to the company’s investment in Dynegy.

      Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2005, and assets as of the end of each year — for the United States and the company’s major international geographic areas — may be found in Note 8 to the consolidated financial statements beginning on page FS-40 of this Annual Report on Form 10-K. In addition, similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are contained in Notes 13 and 14 on pages FS-44 to FS-46.

      Excluding the $17.3 billion acquisition of Unocal Corporation, total reported expenditures for 2005 were $11.1 billion, including $1.7 billion for the company’s share of affiliates’ expenditures, which did not require cash outlays by the company. In 2004 and 2003, expenditures were $8.3 billion and $7.4 billion, respectively, including the company’s share of affiliates’ expenditures of $1.6 billion and $1.1 billion in the corresponding periods.

      Of the $11.1 billion in expenditures for 2005, about three-fourths, or $8.4 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2004 and 2003. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the years, reflecting the company’s continuing focus on opportunities that are available outside the United States.

      In 2006, the company estimates capital and exploratory expenditures will be 33 percent higher at $14.8 billion, including spending by affiliates. About three-fourths, or $11.3 billion, is again targeted for exploration and production activities, with $8 billion of that amount outside the United States.

      Refer also to a discussion of the company’s capital and exploratory expenditures on pagesFS-14 andFS-15 of this Annual Report on Form 10-K.

      The table on the following page summarizes the company’s and affiliates’ net production of liquids and natural gas for 2005 and 2004. As part of the Unocal acquisition in August 2005, Chevron acquired interests in producing operations in Azerbaijan, Bangladesh, Canada, the Democratic Republic of the Congo, Indonesia, Myanmar, the Netherlands, Thailand and the United States. In September 2005, the producing operations in Canada were sold.

      In 2005, Chevron conducted its exploration and production operations in the United States and approximately 35 other countries. Worldwide oil-equivalent production of approximately 2.5 million barrels per day in 2005, including volumes produced from oil sands in Canada and production under an operating service agreement in Venezuela, was about the same as in 2004. Production in the last five months of 2005 included volumes associated with the properties acquired from Unocal. However, production during the year from the heritage-Chevron properties declined from their levels in 2004, due mainly to operations that were offline as a result of August and September hurricanes in the Gulf of Mexico, property sales between periods, the effect of higher prices on volumes required under cost-recovery and variable-royalty provisions of certain contracts, and normal field declines. Refer to the “Results of Operations” section beginning on page FS-7 for a detailed discussion of the factors explaining the 2003 — 2005 changes in production for crude oil and natural gas liquids and natural gas.

      The company estimates that its average oil-equivalent production in 2006 will be in the range of 2.7 to 2.8 million barrels per day. The additional volumes over the 2.5 million barrels per day produced in 2005 are attributable mainly to the properties acquired from Unocal and new projectstart-ups that are expected to help offset normal field declines in existing operations. However, the company cautions that any future estimate of production is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, the rate of recovery of production being restored in the Gulf of Mexico following the 2005 hurricanes, and production that may have to be shut in due to weather conditions, civil unrest, changing geopolitics or other disruptions to daily operations. Expected additions to production capacity in 2007 through 2009 may permit worldwide oil-equivalent production levels to increase from levels in 2006. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 10, for a discussion of the company’s major oil and gas development projects.

      Refer to Table IV on page FS-70 of this Annual Report on Form 10-K for data about the company’s average sales price per unit of crude oil and natural gas produced as well as the average production cost per unit for 2005, 2004 and 2003.

      The following table summarizes gross and net productive wells at year-end 2005 for the company and its affiliates:

      Table V, beginning on page FS-70,provides a tabulation of the company’s proved net oil and gas reserves, by geographic area, as of each year-end 2003 through 2005 and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period. During 2005, the company provided oil and gas reserves estimates for 2004 to the Department of Energy, Energy Information Agency. Such estimates are consistent with, and do not differ more than 5 percent from, the information furnished to the SEC on the company’s Annual Report on Form 10-K. During 2006, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency, consistent with the reserve data reported in Table V.

      At December 31, 2005, the company owned or had under lease or similar agreements undeveloped and developed oil and gas properties located throughout the world. The geographical distribution of the company’s acreage is shown in the following table.

      The company sells crude oil and natural gas from its producing operations under a variety of contractual arrangements. Most contracts generally commit the company to sell quantities based on production from specified properties, but certain natural gas sales contracts specify delivery of fixed and determinable quantities.

      In the United States, the company is contractually committed to deliver to third parties and affiliates approximately 195 billion cubic feet of natural gas through 2008 from United States reserves. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed U.S. reserves. These contracts include variable-pricing terms.

      Outside the United States, the company is contractually committed to deliver to third parties a total of approximately 780 billion cubic feet of natural gas from 2006 through 2008 from Australia, Canada, Colombia and the Philippines. The sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery and in some cases consider inflation or other factors. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves in Australia, Colombia and the Philippines. The company plans to meet its Canadian contractual delivery commitments through third-party purchases.

      Details of the company’s development expenditures and costs of proved property acquisitions for 2005, 2004 and 2003 are presented in Table I on page FS-65 of this Annual Report on Form 10-K.

      The table below summarizes the company’s net interest in productive and dry development wells completed in each of the past three years and the status of the company’s development wells drilling at December 31, 2005. A “development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. “Wells drilling” includes wells for which drilling activities have been temporarily interrupted at the end of 2005.

      The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 2005. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir beyond the proved area. “Wells drilling” includes wells for which drilling activities have been temporarily interrupted at the end of 2005.

     Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2005, 2004 and 2003 are presented in Table I on page FS-65 of this Annual Report on Form 10-K.

      Chevron’s 2005 key upstream activities, also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2, are presented below. The comments below include references to “total production” and “net production,” which are defined in Exhibit 99.1 on page E-11 of this Annual Report on Form 10-K. Certain annual production statistics include volumes from the former Unocal operations from August 1, 2005. In addition to the activities discussed, Chevron was active in other geographic areas, but those activities were less significant.

      The discussion below also references the status of proved reserves recognition for significant long-lead-time projects not yet on production and for projects recently placed on production. Reserves are not discussed for recent discoveries that have yet to advance to a project stage and for production in mature areas.

      The United States upstream activities are concentrated in the Gulf of Mexico, Louisiana, Texas, New Mexico, the Rocky Mountains and California. Average daily net production during 2005 was 455,000 barrels of liquids and 1.6 billion cubic feet of natural gas, or 727,000 barrels per day on an oil-equivalent basis. With the acquisition of Unocal in August 2005, the company obtained properties that complemented and enhanced Chevron’s already-strong positions in the Gulf of Mexico and the Permian Basin in West Texas and New Mexico. Refer to Table V beginning on pageFS-70 for a discussion of the reserves and different characteristics for the company’s major U.S. producing areas.

      In the deepwater areas, the company has an interest in four producing fields: Genesis, Petronius, K2 and Mad Dog. K2 and Mad Dog were added to the portfolio as a result of the Unocal acquisition.

      The 57 percent-owned and operated Genesis Field averaged daily net production of approximately 9,000 barrels of crude oil and 11 million cubic feet of natural gas in 2005, or 11,000 barrels of oil-equivalent.

      Petronius, which is 50 percent-owned and operated, had daily net production of 14,000 barrels of crude oil and 17 million cubic feet of natural gas in 2005, or 17,000 barrels of oil-equivalent. Petronius production was shut in for repairs following hurricane damage in September 2004 and resumed production in March 2005.

      The Perseus discovery, which is part of the Petronius development, began production from its first well in the second quarter 2005. Fromstart-up through year-end, average daily net production was 3,000 barrels of oil-equivalent. A second extended-reach well is expected to begin production in April 2006, with anticipated daily production rates between 3,000 and 7,000 barrels of net oil-equivalent. The Perseus project has an estimated production life of six to nine years, with maximum production anticipated in 2006. The company anticipates the majority of proved undeveloped reserves will be categorized as proved developed by the end of 2006.

      Chevron has a 13 percent nonoperated interest in the former Unocal K2 Field, which had initial production from its first well in May 2005 and increased to approximately 2,000 barrels of net oil-equivalent production per day by November.

      Chevron holds a 16 percent nonoperated interest in the Mad Dog Field, which commenced production in early 2005 and had average daily net production of 4,000 barrels of oil-equivalent for the five months following the acquisition of Unocal. Development work continues in order to increase the daily maximum total production to the design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas and is expected to be complete in 2008. Additional studies are under way to expand the total crude oil production capacity to more than 100,000 barrels per day. The Mad Dog Field has an estimated production life of 20 years. Additional reserve reclassification to proved developed is expected to coincide with the development program through 2008.

      At Typhoon, the tension leg platform suffered catastrophic damage from Hurricane Rita in September 2005. Teams were formed to investigate the cause of the incident and evaluate options to possibly restore operations. Average daily net production prior to the storm from the 50 percent-owned and operated Typhoon Field, along with volumes processed from the nearby 25 percent-owned and nonoperated Boris Field, averaged about 6,000 barrels of oil-equivalent per day. Typhoon and Boris production remained shut-in in early 2006 pending ongoing salvage and restoration studies.

      Development activity continues on the 58 percent-owned and operated Tahiti Field, where productionstart-up is expected in 2008. Most contracts for the engineering, procurement, fabrication and installation of the spar hull, topsides and subsea equipment were awarded in 2005. Construction of the floating production facility began in the fourth quarter. Initial booking of proved undeveloped reserves occurred in 2003, and the transfer of these reserves into the proved developed category is anticipated upon productionstart-up. With an expected production life of 30 years, Tahiti is anticipated to have a maximum total daily production of 125,000 barrels of crude oil and 70 million cubic feet of natural gas.

      At the 63 percent-owned and operated Blind Faith discovery, a subsea development utilizing a semi-submersible production system was approved by Chevron and its partner in late 2005, at which time the company made its initial booking of proved undeveloped reserves. Reclassification of these reserves to the proved developed category is anticipated in the first half 2008, when first production is expected. Initial total daily output is estimated at 30,000 barrels of crude oil and 30 million cubic feet of natural gas.

      Chevron also continues to evaluate development of the 33 percent-owned and nonoperated Great White discovery. Successful appraisal drilling was conducted in 2004, and the partners have formed a project management team to begin front-end engineering and design (FEED) in March 2006. No proved reserves had been recognized for this discovery as of early 2006.

      The company participated in five wells in the Gulf of Mexico deepwater exploration program during 2005. The 2005 program resulted in two announced discoveries and one successful appraisal well. The discoveries were the 25 percent-owned and nonoperated Knotty Head discovery and the 60 percent-owned and operated Big Foot prospect. Additional appraisal activity was ongoing at both locations in early 2006. At the 30 percent-owned and nonoperated

Tubular Bells prospect that was discovered in 2003, further evaluation of commercial potential also continued, with additional follow-updrilling planned for 2006. A successful appraisal well was drilled in 2005 at the 2004 Jack discovery. An extended production test is expected to be under way in March 2006. Evaluation continues at nearby Saint Malo, where a successfulfollow-up appraisal well was drilled during 2004. The first appraisal well also commenced drilling at the nonoperated 2003 Puma discovery; however, the well was not completed as of early 2006 due to extensive weather and rig-related delays. Proved reserves were not yet recognized for any of these prospects as of early 2006.

      Besides the activities connected with the development and exploration projects in the Gulf of Mexico area, Chevron also filed an application with the Federal Energy Regulatory Commission in the third quarter 2005 to own, construct and operate a natural gas import terminal at Casotte Landing in Jackson County, Mississippi. The proposed project, to be located adjacent to the Chevron-owned Pascagoula Refinery, would be designed to process imported liquefied natural gas (LNG) for distribution to industrial, commercial and residential customers in Mississippi and the Southeast region, including the growing Florida market. The terminal would have an initial natural-gas processing capacity of 1.3 billion cubic feet per day.

      The company also exercised an option to increase its capacity at the Sabine Pass LNG terminal to 1 billion cubic feet per day. Additionally in the Sabine Pass area, the company signed an agreement in mid-2005 to secure 1 billion cubic feet per day of pipeline capacity in a new pipeline that will be connected to the Sabine Pass LNG terminal. Interconnect capacity of 600 million cubic feet per day was also secured to an existing pipeline. The new pipeline is planned to be in service in 2009, coinciding with the company’s Sabine Pass terminal commitments. The new pipeline system will provide access to Chevron’s Sabine and Bridgeline pipelines, which connect to the Henry Hub. The Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange (NYMEX) and is located on the natural gas pipeline system in Louisiana. Henry Hub interconnects to nine interstate and four intrastate pipelines.

     Other U.S. Areas: Outside California and the Gulf of Mexico, the company manages operations in areas of the midcontinent United States that extend from the Rockies to southern Texas. The acquisition of Unocal in 2005 added to production operations in the Permian Basin of western Texas and southeastern New Mexico, the San Juan Basin area of New Mexico and Colorado, and in East Texas. Also as a result of the Unocal acquisition, Chevron operates 10 offshore platforms in Alaska and five producing natural gas fields in the Cook Inlet and owns nonoperated production on the North Slope. During 2005, the company’s operations outside California and the Gulf of Mexico averaged daily net production of 126,000 barrels of crude oil and natural gas liquids and 949 million cubic feet of natural gas (284,000 barrels of oil-equivalent).

      In Block 14, net production from the Kuito Field, Angola’s first deepwater producing area, averaged 15,000 net barrels of crude oil per day in 2005. First oil was produced from the Belize Field in January 2006. This was the initial production from Phase 1 of the $2.3 billion integrated drilling and production project for the Benguela, Belize, Lobito and Tomboco fields. Proved undeveloped reserves for both Benguela and Belize were recognized in 1998, and certain volumes for Belize were transferred to proved developed in 2005. The concession period for these fields expires in 2027.

      Phase 2 of the Block 14 development involves the installation of subsea production systems, pipelines and wells for Lobito and Tomboco. Proved undeveloped reserves for these fields were recognized in 2000. Phase 2 is under construction, with first oil planned in late 2006. After both phases are completed, maximum total production in 2008 is estimated at approximately 200,000 barrels per day of crude oil. Proved developed reserves are expected to be recognized near the time of first oil once certain project milestones have been met. The concession period for these fields expires in 2027.

      The Tombua and Landana fields in Block 14 were discovered in 1997 and 2001, respectively, and appraisal drilling was conducted from 1998 through 2002. Proved undeveloped reserves for Tombua and Landana were recognized in 2001 and 2002, respectively. The Tombua-Landana development is targeted as the next major capital project for Block 14, with FEED having begun in 2005. Estimated capital expenditures for the development exceed $2 billion. The concession period expires in 2028.

      Chevron also has two other concessions in Angola — Block 2, 20 percent-owned and operated, and the joint venture FST area, in which the company has a 16 percent nonoperated interest. Net production from these properties in 2005 totaled 5,000 barrels of crude oil per day. Sonangol, Angola’s national oil company, is scheduled to become operator of Block 2 during 2006.

      In addition to the producing activities in Angola, the company also has a 36 percent interest in the planned Angola LNG project, which will be integrated with natural gas production in the area. In April 2005, the project partners awarded FEED contracts for a5-million-metric-ton-per-year onshore LNG plant in the northern part of the country. Chevron and Sonangol are co-leaders of the project. Construction is expected to begin in 2007. Proved natural gas reserves associated with this project have not yet been recognized.

     Democratic Republic of the Congo: As a result of the Unocal acquisition, Chevron acquired an 18 percent nonoperated working interest in a production-sharing contract off the coast of the Democratic Republic of the Congo. Daily net production for the five months after the Unocal acquisition from the seven acquired fields averaged 2,000 barrels of crude oil.

     Republic of the Congo: Chevron has a 32 percent interest within the Haute Mer area (Nkossa, Nsoko and Moho-Bilondo exploitation permits) and a 29 percent interest within the Marine VII area (Kitina and Sounda exploitation permits), all of which are offshore Republic of the Congo and adjacent to the company’s concessions in Angola. Net production from the Republic of the Congo properties averaged 11,000 barrels of crude oil per day in 2005. The Moho and Bilondo satellite field development was approved in 2005, with first production expected in 2008. Proved undeveloped reserves were initially recognized in 2001. Transfer to the proved developed category is expected near the time of first production. The Moho-Bilondo concession expires in 2030.

     Southern Africa: The Lianzi-2 appraisal well was drilled in 2005 to assess the size and commerciality of the successfulLianzi-1 well drilled in the 14K/A-IMI Unit, located in a joint development area shared between the Republic of the Congo and Angola, in which the company is operator and holds a 31 percent interest. No proved reserves had been recognized as of early 2006.

     Chad-Cameroon: Chevron is a nonoperating partner in a project to develop crude oil fields in southern Chad and transport crude oil by pipeline to the coast of Cameroon for export. Average daily net production from three fields in 2005 was 38,000 barrels of crude oil. Proved undeveloped reserves were recorded in 2000 and most have been reclassified to proved developed reserves. Over the next three to four years, additional reserves will be transferred to the proved developed category as additional wells are drilled, facilities are expanded and reservoir pressure-support projects are in place. Production began in 2003, and the life of the fields is estimated at 30 years. Chevron has a 25 percent interest in the upstream operations and a 21 percent interest in the pipeline.

     Libya: In early 2005, the company was awarded Block 177 in Libya’s first exploration license round under the Exploration and Production Sharing Agreement IV. Chevron will operate Block 177 with a 100 percent equity interest. A work program is under way, and contracting for the acquisition of seismic data is scheduled to begin in 2006.

      Onshore operations in the Niger Delta with a net production capacity of approximately 45,000 barrels of crude oil per day, including the Olero Creek development, were suspended in 2003 as a result of the ongoing civil unrest. The Abiteye Field, closest to the Escravos terminal, was returned to production in 2004. Repairs to the Makaraba Flow Station were completed in mid-2005, allowing for the resumption of production of 6,000 net barrels per day from the Abiteye, Makaraba and Utonana fields and the Eastern Region. Further restoration of select Dibi wells and flowlines in late 2005 contributed to an additional 6,500 net barrels per day from the Dibi Field. As of year-end 2005, approximately 13,000 of the 45,000 barrels per day had been returned to production. Restoration activities in the remaining fields will continue at least through 2006.

      During 2005, the company continued development activities for the deepwater Agbami project. The company’s share of capital investment for the full project is estimated at $3.4 billion. In early 2005, the project achieved the following major milestones: conversion of Oil Prospecting License (OPL) 216 and OPL 217 to Oil Mining Lease (OML) 127 and OML 128; approval of the field development plan; award of the contract for the floating production, storage and offloading (FPSO) vessel; execution of the unit agreement; award of the subsea equipment, subsea installation and offloading system contracts; and approval of initial project funding by the partners. Five development wells were drilled in 2005, and development drilling is scheduled to continue through 2009. Proved undeveloped reserves were recognized for this project in 2002. Prior to the anticipated productionstart-up in 2008, certain proved undeveloped reserves are expected to be reclassified to proved developed reserves. The expected field life is approximately 20 years. Maximum total daily production of 250,000 barrels of liquids is expected to be reached within six to 12 months followingstart-up.Chevron’s ownership interest under the unit agreement is 68 percent.

      For the 2003 Aparo discovery on OPL 213, Chevron signed a joint-study agreement in 2004 with the operator of OPL 212 to conduct technical studies in pursuit of a unitized joint development of the Aparo and Bonga SW fields, which straddle OPL 212, OPL 213 and OPL 249. Unitization discussions continued through 2005, and a pre-unit agreement is expected to be signed by the end of the first quarter 2006. Development will likely involve an FPSO and subsea wells. FEED and basic engineering are expected to commence by the end of the first quarter 2006. Chevron’s initial interest in the unitized field is anticipated to be 20 percent. Proved undeveloped reserves are expected to be recognized in 2006, and productionstart-up is targeted for late 2010.

      Chevron operates and holds a 95 percent interest in the OPL 249 Nsiko discovery. The discovery well was drilled in 2003, followed by two successful appraisal wells in 2004. Subsurface evaluations and field development planning continued in 2005. FEED and basic engineering are expected to commence in late 2006.

      In OPL 222 during 2005, activities continued in the greater Usan area with the successful drilling of the seventh and eighth appraisal wells. The Usan field-development plan was approved in 2005, and in early 2006, regulatory

approval of the OML conversion for the Usan development was in the process of being finalized. Once approved, the end date of the concession period will be determined. Proved undeveloped reserves were recorded in 2004 for the Usan Field, and development entered its basic engineering phase in 2005. Production start-up is estimated for late 2010, before which time certain proved undeveloped reserves are expected to be reclassified to the proved developed category. The company holds a 30 percent nonoperated interest in this project.

      The Nnwa Field, discovered in OPL 218 in 1999, extends into adjacent blocks OPL 219 and OPL 246. Commerciality of the field is under evaluation. During 2005, OPL 218 was converted to OML 129.

      At the Escravos Gas Plant (EGP), onshore and offshore engineering, procurement and construction bids were awarded in early 2005 for the Phase 3 expansion of the natural gas processing facilities. Early site work began in late 2005, and construction commenced in February 2006.Start-up is expected in 2008 and includes adding a second natural gas plant with 395 million cubic feet of capacity, potentially increasing capacity to 680 million cubic feet of natural gas per day and LPG and condensate exports to 43,000 barrels per day. Proved undeveloped reserves associated with EGP Phase 3 were recognized in 2002. These reserves are expected to be reclassified to proved developed as various stages of EGP and related projects are completed. The anticipated life of the project is 25 years. Chevron holds a 40 percent operated interest in this project.

      Refer to page 30 for a discussion on the planned Escravosgas-to-liquids facility.

      The West African Gas Pipeline regional project is planned to supply Nigerian natural gas to customers in Ghana, Benin and Togo for industrial applications and power generation. Chevron holds a 38 percent interest in the project. Detailed engineering and the award of several major construction contracts occurred in early 2005. In the third quarter 2005, the company commenced installation of a350-mile main offshore segment of the West African Gas Pipeline that will connect to an existing onshore pipeline in Nigeria.Start-up is expected in late 2006. Chevron is the managing sponsor in West African Pipeline Company Limited, which will construct, own and operate the pipeline.

      The South Offshore Water Injection Project (SOWIP) is an enhanced crude-oilrecovery project in the south offshore area of OML 90. Chevron holds a 40 percent interest as part of the joint venture with NNPC. The objective of the SOWIP is to increase production by providing water injection, natural gas lift and production de-bottlenecking in the South Offshore Asset Area (Okan and Delta fields). Offshore construction and commissioning activities were under way in early 2006. Incremental proved reserves were recognized for SOWIP in 2005. The project has an expected 25-year life.

      In April 2005, Chevron entered into a memorandum of understanding (MOU) with partners to evaluate the viability of an LNG plant at the Olokola site located in a free trade zone between Lagos and Escravos. The plans for the proposed LNG plant, in which Chevron anticipates holding a 19 percent interest, include a phased development of four processing trains (5.5 million metric tons per year each). FEED is expected to commence by the end of the first quarter 2006. The project is expected to start up in 2010 or 2011. CNL is expected to supply approximately 1.8 billion cubic feet per day of natural gas to the project. CNL is in the process of completing the certification of the reserves required to satisfy the natural gas supply requirements for this project. No proved reserves had been recognized as of early 2006.

     Nigeria - São Tomé e Príncipe Joint Development Zone (JDZ): The company was awarded JDZ Block 1 in 2004. In early 2005, the company signed a production-sharing contract with the Joint Development Authority, under which Chevron will be the operator with a 51 percent interest. The first exploration well began drilling in January 2006, with planned completion of drilling operations in March 2006.

      On Barrow and Thevenard islands, Chevron operates crude oil producing facilities that had combined net production of 6,000 barrels per day in 2005. Chevron’s equity interest in this operation is 57 percent for Barrow Island and 51 percent for Thevenard Island.

      Chevron also is the operator of the Gorgon-area fields and has interests in other Greater Gorgon fields off the northwest coast of Australia. Twelve discovered natural gas fields straddle 17 lease blocks in the Greater Gorgon Area. Chevron and its two joint-venture participants signed a Framework Agreement in April 2005 that will enable the combined development of Gorgon and the nearby natural gas fields as one world-scale project. Chevron has a 50 percent ownership interest across most of the Greater Gorgon Area. The Gorgon Project awarded upstream and downstream FEED and engineering, procurement and construction contracts in June 2005 for a two-train (10 million metric tons per year) LNG facility and a possible domestic natural gas plant on Barrow Island, targeting initial production by 2010. Proved reserves have not been recognized for any of the Gorgon-area fields. Recognition is contingent on securing sufficient LNG sales agreements and other key project milestones.

      In the fourth quarter 2005, the company signed separate nonbinding Heads of Agreements with three companies in Japan to supply LNG from the Gorgon project. Negotiations are under way to finalize binding sales agreements. Purchases will range from 1.2 million metric tons per year to 1.5 million metric tons per year of LNG over 25 years, commencing in 2010 and 2011.

      During 2005 and early 2006, the company was awarded exploration rights to five deepwater blocks in the Carnarvon Basin offshore Western Australia. Chevron holds a 50 percent, operated interest in the blocks. Two-dimensional(2-D) seismic survey was acquired over four of the blocks.

      Also in 2005, 3-Dseismic survey was acquired for the wholly ownedWheatstone-1 2004 natural gas discovery offshore Western Australia. Two appraisal wells were also completed in the Browse Basin, located offshore northwest Australia.

      Interests ranging from 25 percent to 50 percent in three blocks offshore southern Australia and two blocks in northwest Australia were added to Chevron’s portfolio through the Unocal acquisition. The company is working with partners on a detailed technical evaluation of the blocks in southern Australia. The blocks in the northwest have well commitments that are targeted for drilling in the next three years.

     Kazakhstan: Chevron holds a 20 percent nonoperated interest in the Karachaganak project that is being developed in phases. Phase 2 of the field development was completed in 2004, and Phase 3 was under evaluation as of early 2006. Access for Karachaganak production to the Caspian Pipeline Consortium (CPC) pipeline allows sales of approximately 150,000 barrels per day of processed liquids (28,000 net barrels) at prices available in world markets. During 2005, Karachaganak daily net production averaged 37,000 barrels of liquids and 142 million cubic feet of natural gas. Proved developed reserves associated with Phase 2 were added in 2002 through 2005. The Karachaganak operations are conducted under a40-year concession agreement that expires in 2038. Timing for the recognition of Phase 3 reserves and an increase in production are uncertain and depend on achieving a natural gas sales agreement. Refer also to page 23 for a discussion of Tengizchevroil, a 50 percent-owned affiliate with operations in Kazakhstan.

     Russia: In 2005, OAO Gazprom included Chevron on a list of companies that could continue further commercial and technical discussions concerning the development and related commercial activities of the Shtokmanovskoye Field. Discussions were under way in early 2006, but the timing of Gazprom’s selection of the company or companies that will participate in the field development was uncertain. Shtokmanovskoye is a very large natural gas field offshore Russia in the Barents Sea. OAO Gazprom is Russia’s largest natural gas producer.

     Turkey and Georgia: Chevron is the operator of the Silopi Block in southeast Turkey with a 25 percent interest. It also has a 25 percent interest in Turkey Black Sea deepwater Block 3534, which was part of the Unocal acquisition. Also as part of the Unocal acquisition, Chevron holds 10 percent interests in several adjacent blocks in Georgia.

     Bangladesh: Through the Unocal acquisition, Chevron became operator of four blocks, with a 98 percent interest in Blocks 12, 13 and 14 and a 43 percent interest in Block 7. For the five-month period after the acquisition, the properties averaged daily net production of 141 million cubic feet of natural gas. In early 2006, Chevron was supplying about 20 percent of the natural gas market in Bangladesh. Chevron plans to build a natural gas processing plant and natural gas pipeline in connection with a 2004 agreement to produce natural gas from the Bibiyana Field in Block 12. Initial production is expected late in the fourth quarter 2006. Additional proved reserves are expected to be recorded in 2006. The Bibiyana production-sharing contract expires in 2034. First production from the Moulavi Bazar Field began in March 2005. The Moulavi Bazar production-sharing contract expires in 2028.

     Myanmar: As a result of the Unocal acquisition, Chevron has a 28 percent nonoperated working interest in a production-sharing contract for the production of natural gas from the Yadana Field, located offshore Myanmar in the Andaman Sea. The company also has a 28 percent ownership interest in a pipeline company that transports the natural gas from the Yadana Field to the Myanmar-Thailand border for final delivery to power plants in Thailand. Average net natural gas production following the acquisition was 76 million cubic feet per day.

     Thailand: Chevron operates Blocks B8/32, 9A and G4/43 in the Gulf of Thailand. The company holds a 52 percent interest in Blocks B8/32 and 9A and a 60 percent interest in Block G4/43. Through the Unocal acquisition, the company also has operated interests ranging from 35 percent to 80 percent in Blocks 10 through 13 and 12/27 and a 16 percent nonoperated interest in Blocks 14A, 15A and 16A, known collectively as the Arthit Field. Chevron also holds both operated and nonoperated interests ranging from 33 percent to 80 percent in a number of exploration blocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.

      Block B8/32 produces crude oil and natural gas from four fields: Benchamas, Maliwan, North Jamjuree and Tantawan. Block 9A was brought online in 2005. Daily net production in 2005 from these two blocks was 105 million cubic feet of natural gas and 25,000 barrels of crude oil. Also in 2005, the company completed the development study for the Block 8/32 Central Belt Area, with first production anticipated in 2007.

      Two appraisal wells were drilled in Block G4/43 in early 2005 and resulted in the successful extension of the Similan and Lanta oil trends. In addition,3-D seismic data acquisition and processing relating to other prospects were completed in August 2005. First crude oil production is anticipated in early 2007.

      In the acquired Unocal operations, three platforms were installed in the Pailin and Kaphong areas and 90 wells were drilled post-merger. De-bottlenecking of several central processing platforms was nearly completed in 2005, which is expected to add more than 150 million cubic feet per day of natural gas processing capability. Thai Oil Phase 2 development of the offshore crude oil project in the Pattani Field started up in May 2005. Chevron has the right to operate in this concession until 2022. Phase 1 development of the Arthit Field began in late 2005, with first production planned for 2007. Net production from these areas for the last five months of 2005 averaged 726 million cubic feet per day of natural gas and 43,000 barrels of crude oil and condensate per day.

     Vietnam: As a result of the Unocal acquisition, the company has two production-sharing contracts offshore southwest Vietnam in the northern part of the Malay Basin. Chevron has a 42 percent interest in Blocks B and 48/95 and a 43 percent interest in Block 52/97. In 2005, the company was awarded a 50 percent interest and will be the operator in Block 122, located offshore eastern Vietnam.

     China: Chevron has a 33 percent nonoperated interest in Blocks 16/08 and 16/19, located in the Pearl River Delta Mouth Basin; a 25 percent interest inQHD-32-6 in Bohai Bay; and a 16 percent working interest in the unitized and producing Bozhong 25-1 Field in Bohai Bay Block 11/19. Daily net production from the company’s interests in China averaged 26,000 barrels of crude oil in 2005. The company also has interests ranging from 50 percent to 64 percent in four prospective onshore natural gas blocks totaling about 1.6 million acres.

     Partitioned Neutral Zone (PNZ): Saudi Arabian Texaco Inc., a Chevron subsidiary, holds a60-year concession that expires in 2009 to produce crude oil from onshore properties in the PNZ, which is located between the Kingdom of Saudi Arabia and the State of Kuwait. As of early 2006, the company was actively seeking an extension or renewal of the agreement. The company, by virtue of its concession, has the right to Saudi Arabia’s 50 percent undivided interest in the hydrocarbon resource and pays a royalty and other taxes on volumes produced. During 2005, average daily net production was 112,000 barrels of crude oil and 22 million cubic feet of natural gas. Construction of steamflood pilot facilities was completed in 2005. The facilities serve as a precursor for a second-phase pilot project that was in the front-end engineering stage in early 2006. The second phase entails drilling 16 injection wells, 25 producing wells and the installation of water-treatment and steam-generation facilities. The estimated total project cost is more than $300 million. This is the first project of its type in the Middle East.

     Philippines: The company holds a 45 percent nonoperated interest in the Malampaya natural gas field located about 50 miles offshore Palawan Island. Daily net production in 2005 was 163 million cubic feet of natural gas and 8,000 barrels of condensate. As a result of the Unocal acquisition, Chevron also develops and produces steam resources under an agreement with the National Power Corporation, a Philippine government-owned company. The combined installed generating capacity is 634 megawatts.

      A development concept for the Sadewa project, located in the Kutei Basin, is scheduled for selection in 2006, with initial proved reserves recognition planned for 2007. First production is expected in 2008. The company also advanced development plans during 2005 for its Gendalo Hub and Gehem Hub deepwater natural gas projects, also located in the Kutei Basin. Development concepts are expected to be selected in 2006. These projects will likely be developed in parallel, with first production for both projects targeted for the 2010 to 2012 time frame. The actual timing is partially dependent on government approvals and market conditions. In addition, development is progressing on steamflood activity in North Duri.

      Heritage-Chevron’s share of net production in CPI-operated areas during 2005 was 193,000 barrels of oil-equivalent per day. Daily net production from South Natuna Sea Block B in 2005 averaged 21,000 barrels of oil-equivalent. Net production from the acquired Unocal operations was 56,000 barrels of oil-equivalent per day for five months ended December 31, 2005.

nonoperated interest in the BM-C-4 Block in which one exploration well is planned during 2006. In the 20 percent-owned and nonoperated Santos Basin BS-4 Block, an additional appraisal well is planned for the second quarter 2006.

      In the Frade Field (Block BC-4),located in the Campos Basin, the company is the operator and has a 43 percent interest. FEED for a floating, production, storage and offloading vessel and subsea production systems was completed in 2005. Project sanction is expected in 2006, with first oil expected in 2008. Proved undeveloped reserves were recorded for the first time in 2005. The Frade concession expires in 2025.

     Colombia: The company operates three natural gas fields in Colombia — the offshore Chuchupa and the onshore Ballena and Riohacha. The fields are part of the Guajira Association contract, a joint venture production-sharing agreement, which was extended in 2003. At that time, additional proved reserves were recognized. The company continues to operate the fields and receives 43 percent of the production for the remaining life of each field as well as a variable production volume from a fixed-fee Build-Operate-Maintain-Transfer (BOMT) agreement based on prior Chuchupa capital contributions. The BOMT agreement expires in 2016. Net production averaged 185 million cubic feet of natural gas per day in 2005. New production capacity is scheduled for commissioning in 2006 and will help meet the demand from the growing Colombian natural gas market.

     Trinidad and Tobago: The company has a 50 percent nonoperated interest in four blocks in offshore Trinidad, which include the producing Dolphin natural gas field and two discoveries, Dolphin Deep and Starfish. Net natural gas production from the Dolphin Field in 2005 averaged 115 million cubic feet per day. Natural gas supply to the Atlantic LNG Train 3 from the Dolphin Field began in November 2005. Initial recognition of proved undeveloped reserves associated with the natural gas sales agreement for Train 3 was made in 2003. Proved reserves associated with the Train 4 gas sales agreement were recognized in 2004. Initial production of the Train 4—related reserves is scheduled for the first half of 2006. Reserves associated with Trains 3 and 4 were transferred to the proved developed category in 2005. The contract period for Train 3 ends in 2023 and for Train 4 in 2026. Chevron also holds a 50 percent, operated interest in Block 6d. In early 2005, the company announced successful exploration drilling results at the offshore Manatee 1 exploration well in Block 6d. The company is assessing alternative development strategies. A unitization agreement is being negotiated between Trinidad and Tobago and Venezuela to develop and produce the Loran and Manatee fields as one project.

     Venezuela: The company operates the onshore Boscan Field under an operating services agreement and receives operating expense reimbursement and capital recovery, plus interest and an incentive fee. Daily net production in 2005 averaged 111,000 barrels of crude oil. The company has not recorded proved reserves under this agreement. The company also has production at the 63 percent-owned LL-652 Field located in Lake Maracaibo. Net production in 2005 averaged 10,000 barrels of oil-equivalent per day. The company operates at LL-652 under a risked service agreement.

      In 2005, the Venezuelan government stipulated that the existing Boscan and LL-652 operating service agreements be converted to an Empresa Mixta (EM), or a Joint Stock contractual structure, with Petróleos de Venezuela, S.A. (PDVSA) as majority shareholder. In December 2005, Chevron signed a transition agreement with PDVSA in order to negotiate the ownership and format of the final EM structure during 2006. Possible financial implications of the EM structure are uncertain but are not expected to have a material effect on the company’s consolidated financial position or liquidity.

      The company has ongoing exploration activity in two blocks offshore Plataforma Deltana. In Block 2, which includes Loran Field, evaluation and project development work continue after an exploration and appraisal program was completed in 2005. Proved reserves have not been recognized for this project. The company is operator and holds a 60 percent interest. In the 100 percent-owned and operated Plataforma Deltana Block 3, Chevron drilled the successful Macuira natural gas discovery well in 2005. This discovery is in close proximity to the Loran natural gas field and provides significant resources that will be included in the detailed evaluation of a project for the possible construction of Venezuela’s first LNG train. Seismic work in Block 3 is planned for 2006. Chevron was awarded the exploration license in 2005 for the 100 percent-owned Cardon III exploration block, located offshore western Venezuela. The block has natural gas potential to the north of the Maracaibo producing region.

      Refer also to page 24 for a discussion of the Hamaca heavy oil production and upgrading project in Venezuela.

     Canada: Following the acquisition of Unocal, the company completed the sale of Northrock Resources Limited for approximately $1.7 billion. The company continues to maintain strategically significant assets in Canada, including a 27 percent nonoperated interest in the Hibernia Field; a 20 percent nonoperated interest in the Athabasca Oil Sands Project, which is discussed separately on page 29; a 28 percent operated interest in the Hebron project, where feasibility studies preceding the major development project are continuing; and exploration opportunities in the Mackenzie Delta and Orphan Basin. Excluding Athabasca and Northrock, daily net production in 2005 from the company’s Canadian operations was 52,000 barrels of crude oil and natural gas liquids and 6 million cubic feet of natural gas.

     Norway: At the Draugen Field, where Chevron holds an 8 percent nonoperated interest, the company’s share of production during 2005 was 8,000 barrels of crude oil per day. In September 2005, Chevron participated in the drilling of the Mojave exploration well (also known as Stetind) in PL 283, in which the company holds a 25 percent

nonoperated interest. The results of this natural gas well were being evaluated in early 2006. In PL 324, in which the company has a 30 percent nonoperated interest, drilling is planned for late 2006. In the 40 percent-owned and operated PL 325, a seismic program will be conducted in mid-2006.

     United Kingdom: Offshore United Kingdom, the company’s daily net production in 2005 from several fields was 83,000 barrels of crude oil and 300 million cubic feet of natural gas. Daily net production at the 85 percent-owned and operated Captain Field was 42,000 barrels of crude oil. The company’s share of daily net production in 2005 at the co-operated and 32 percent-owned Britannia Field was 8,000 barrels of crude oil and 176 million cubic feet of natural gas. At the Alba Field in the North Sea, in which Chevron holds a 21 percent interest and operatorship, daily net production averaged 12,000 barrels of crude oil.

      In the fourth quarter 2005, the company was awarded equity in eight exploration blocks under the 23rd United Kingdom Offshore Licensing Round. Four blocks are located adjacent to the Rosebank/ Lochnagar offshore discovery. Chevron will be the operator with a 40 percent interest.

      Chevron also holds a 19 percent interest in Clair, a nonoperated development. Initial production began in February 2005 and is expected to attain an average daily net production of 12,000 barrels of crude oil and 3 million cubic feet of natural gas in late 2006. Initial recognition of proved reserves was in 2001. Some reserves were reclassified from proved undeveloped to proved developed in late 2004. Further reclassifications are expected to occur through 2008 related to planned development drilling. Clair has an expected field life of more than 20 years.

      Joint development activities continued at the Britannia satellite fields, Callanish and Brodgar, where Chevron holds 17 percent and 25 percent interests, respectively. Four development wells were completed in 2005. First production is expected in early 2007, building to planned daily net production of 10,000 barrels of crude oil and 50 million cubic feet of natural gas several months afterstart-up. Proved undeveloped reserves were initially recognized in 2000.In 2006, proved undeveloped reserves are expected to be reclassified to proved developed ahead of planned commencement of production in early 2007. This development has an expected production life of approximately 15 years.

      Design and construction work progressed on the Captain Area C project to develop the eastern portion of the Captain Field, with first oil planned for mid-2006.

      The Alder discovery, west of the Britannia Field, is being evaluated as a tie-back to existing infrastructure. Productionstart-up is anticipated in 2009. Initial reserves are planned to be booked in 2008.

     Mexico: In early 2005, the company executed the concession title that would allow construction of the proposed Baja LNG terminal based in offshore Mexican territorial waters. If approved by the company and various government agencies, the terminal would be constructed using a gravity-based structure design with an initial processing capacity of approximately 700 million cubic feet per day.

     Kazakhstan: The company holds a 50 percent interest in Tengizchevroil (TCO), which is developing the Tengiz and Korolev crude oil fields located in western Kazakhstan under a40-year concession that expires in 2033. Net production in 2005 averaged 136,000 barrels per day of crude oil and natural gas liquids and 216 million cubic feet of natural gas.

      TCO is currently undertaking a significant expansion composed of two integrated projects referred to as the Second Generation Plant (SGP) and Sour Gas Injection (SGI). At a total cost of approximately $5.5 billion, these projects are designed to increase TCO’s crude oil production capacity by the third quarter 2007 from the current 300,000 barrels per day to between 460,000 and 550,000 barrels. The actual production level within the estimated range is dependent partially on the effects of the SGI, which are discussed below.

      SGP involves the construction of a large processing train for treating crude oil and the associated sour (i.e., high in sulfur content) gas. The SGP design is based on the same conventional technology employed in the existing processing trains. In addition to new processing capacity, SGP involves drilling and/or completing 55 production wells in the Tengiz and Korolev reservoirs to generate the volumes required for the new processing train. Proved undeveloped reserves associated with SGP were recognized in 2001. Some of these reserves were reclassified to proved developed in

2005, based upon completion of specified project milestones. Over the next decade, ongoing field development is expected to result in the reclassification of additional proved undeveloped reserves to proved developed.

      SGI involves taking a portion of the rich, sour gas separated from the crude oil production at the SGP processing train and re-injecting it into the Tengiz reservoir. Chevron expects that SGI will have two key effects. First, SGI will reduce the sour gas processing capacity required at SGP, thereby increasing liquid production capacity and lowering the quantities of sulfur and gas that would otherwise be generated. Second, over time it is expected that SGI will increase production efficiency and recoverable volumes due to the maintenance of higher reservoir pressure from the gas re-injection. Between 2007 and 2008, the company anticipates recognizing additional proved reserves associated with the SGI expansion. The primary SGI risks include uncertainties about compressor performance associated with injecting high-pressure sour gas and subsurface responses to injection.

      Essentially all of TCO’s production is exported through the Caspian Pipeline Consortium (CPC) pipeline that runs from Tengiz in Kazakhstan to tanker loading facilities at Novorossiysk on the Russian coast of the Black Sea. CPC is working on obtaining shareholder approval for an expansion to fully accommodate increased TCO volumes by 2009. During 2005, TCO sanctioned the Crude Export project and awarded commercial contracts, which will provide additional export routes utilizing rail transportation to the Odessa Ukraine marine terminal and to marine terminals in Aktau, Kazakhstan. In conjunction with existing CPC capacity, the Crude Export project is expected to provide TCO with sufficient capacity to export all TCO production, including volumes produced by SGI/ SGP, prior to expansion of the CPC pipeline.

     Venezuela: Chevron has a 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco Belt. The crude oil upgrading began in October 2004. In the first quarter 2005, the facility reached total design capacity of processing and upgrading 190,000 barrels per day of heavy crude oil (8.5° API) into 180,000 barrels of lighter, higher-value crude oil (26° API). In 2005, net production averaged 41,000 barrels of oil-equivalent per day.

      The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Outside the United States, the majority of the company’s natural gas sales occur in Thailand, the United Kingdom, Australia, and Latin America, and in the company’s affiliate operations in Kazakhstan. International natural gas liquids sales take place in Africa, Australia and Europe. Refer to “Selected Operating Data,” on pageFS-12 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s natural gas and natural gas liquids sales volumes.

      At the end of 2005, the company’s refining system consisted of 19 fuel refineries and an asphalt plant. The company operated nine of these facilities, and 11 were operated by affiliated companies. For these 20 facilities, crude oil distillation capacity utilization averaged 86 percent in 2005, compared with 89 percent in 2004. In general, this decrease resulted from planned and unplanned downtime as well as the impact of two hurricanes in the third quarter 2005. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 90 percent in 2005, compared with 96 percent in 2004, and cracking and coking capacity utilization averaged 76 percent and 88 percent in 2005 and 2004, respectively. Cracking and coking units, including fluid catalytic cracking units, are the primary facilities used in fuel refineries to convert heavier products to gasoline and other light products.

      In 2005, the company began an expansion of the Pascagoula, Mississippi, refinery’s fluid catalytic cracking unit to increase its production of gasoline and other light products. Additionally, GS Caltex, the company’s 50 percent-owned affiliate, approved an upgrade project at the650,000-barrel-per-day Yeosu refining complex in South Korea. At a total estimated cost of $1.5 billion, this project is designed to increase the yield of high-value refined products and reduce feedstock costs through the processing of heavy crude oil.Start-up of these two projects is expected in 2006 and 2007, respectively.

      The company’s U.S. West Coast and Gulf Coast refineries produce low-sulfur fuels that meet 2006 federal government specifications. Investments required to produce low-sulfur fuels in Europe, Canada and South Africa have been completed, and clean fuels projects in Australia are scheduled for completion in 2006.

      The company processes imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 83 percent and 81 percent of Chevron’s U.S. refinery inputs in 2005 and 2004, respectively.

The daily refinery inputs for 2003 through 2005 for the company and affiliate refineries are as follows:

     Product Sales: The company markets petroleum products throughout much of the world. The principal brands for identifying these products are “Chevron,” “Texaco” and “Caltex.”

      The following table shows the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2005.

      In the United States, the company markets under the Chevron and Texaco brands. The company supplies directly or through retailers and marketers almost 9,300 branded motor vehicle retail outlets, concentrated in the southeastern, southwestern and western states. Approximately 600 of the outlets are company-owned or -leased stations. By the end of 2005, the company was supplying more than 1,600 Texaco retail sites, primarily in the Southeast and West. Further expansion is planned when all rights to the Texaco brand in the United States revert to Chevron in July 2006.

      Outside the United States, Chevron supplies directly or through retailers and marketers approximately 17,200 branded service stations, including affiliates, in nearly 90 countries. In British Columbia, Canada, the company markets under the Chevron brand. In Europe, the company has marketing operations under the Texaco brand primarily in the United Kingdom, Ireland, the Netherlands, Belgium and Luxembourg. In West Africa, the company operates or leases to retailers in Cameroon, Côte d’Ivoire, Nigeria, Republic of the Congo, Togo and Benin. In these regions, the company uses the Texaco brand. The company also operates across the Caribbean, Central America and South America, with a significant presence in Brazil, using the Texaco brand. In the Asia-Pacific region, Southern, Central and East Africa, Egypt, and Pakistan, the company uses the Caltex brand.

      The company also operates through affiliates under various brand names. In Denmark and Norway, the company operates through its 50 percent-owned affiliate, HydroTexaco, using the Y-X and Uno-X brands. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex, using the GS Caltex brand. The company’s 50 percent-owned affiliate in Australia operates using the Caltex, Caltex Woolworths and Ampol brands. In the United Arab Emirates, the company sold its 40 percent interest in the Emirates Petroleum Products Co. joint venture in 2005.

      The company continued the marketing and sale of service station sites, focusing on selected areas outside the United States in 2005. More than 700 service stations were sold, primarily in the United Kingdom and Latin America. Since the beginning of 2003, the company has sold its interests in more than 2,300 service station sites. The vast majority of these sites will continue to market company-branded gasoline through new supply agreements.

      The company also manages other marketing businesses globally. Chevron markets aviation fuel in approximately 70 countries, representing a worldwide market share of about 12 percent, and is the leading marketer of jet fuels in the United States. The company also markets an extensive line of lubricant products in about 175 countries.

     Pipelines: Chevron owns and operates an extensive system of crude oil, refined products, chemicals, natural gas liquids and natural gas pipelines in the United States. The company also has direct or indirect interests in other U.S. and international pipelines. The company’s ownership interests in pipelines are summarized in the following table.

     In the United States, the company increased its equity ownership in Bridgeline Holdings, L.P. (BLH) to 100 percent in 2005. Located in southern Louisiana along the Mississippi River corridor, BLH manages and operates an integrated intrastate natural gas pipeline and storage system, consisting of more than 1,000 miles of pipeline and 12 billion cubic feet of natural gas storage capacity, and manages marketing, supply and transportation functions. Through the Unocal acquisition, the company obtained operated and nonoperated interests in natural gas storage assets in Canada, Texas and Alaska, with total storage capacity of 74 billion cubic feet. In addition, the company acquired ownership of the Beaumont Terminal, a nonregulated terminal in Texas that handles a range of commodities. The acquisition also provided the company with ownership interests in about 2,000 net pipeline miles, including a 23 percent interest in the Colonial Pipeline Company and a 64 percent interest in the Southcap Pipeline Company.

      Chevron also has a 15 percent ownership interest in the Caspian Pipeline Consortium (CPC). CPC operates a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. At the end of 2005, CPC had 11 transportation agreements in place and was transporting an average of 520,000 barrels of crude oil per day from the Caspian region. Russian crude oil entered the pipeline in late 2004 and averaged 130,000 barrels per day during 2005, bringing the total volume transported to 650,000 barrels of crude oil per day.

      For information on projects under way related to the Chad-Cameroon pipeline, the West African Gas Pipeline, the Baku-Tbilisi-Ceyhan pipeline and the expansion of the CPC pipeline, refer to pages 14, 16, 18 and 24, respectively.

     Tankers: At any given time during 2005, the company had approximately 70 vessels under a voyage basis or time charter of less than one year. Additionally, all tankers in Chevron’s controlled seagoing fleet were utilized during 2005. The following table summarizes cargo transported on the company’s controlled fleet.

     Federal law requires that cargo transported between U.S. ports be carried in ships built and registered in the United States, owned and operated by U.S. entities and manned by U.S. crews. At year-end 2005, the company’s U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast and the East Coast, and from California refineries to terminals on the West Coast and in Alaska and Hawaii.

      The international flag vessels were engaged primarily in transporting crude oil from the Middle East, Indonesia, Mexico and West Africa to ports in the United States, Europe and Asia. Refined products were also transported by tanker worldwide.

      In addition to the vessels described above, the company owns a one-sixth interest in each of seven liquefied natural gas (LNG) tankers transporting cargoes for the North West Shelf (NWS) project in Australia. Additionally, the NWS project has two LNG tankers under long-term time charter. In 2005, the company placed orders for two additional LNG tankers to support planned growth in the company’s LNG business. These carriers are planned to be delivered in 2009.

      The Federal Oil Pollution Act of 1990 requires the scheduled phase-out, by year-end 2010, of all single-hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone. This has raised the demand for double-hull tankers. By the end of 2005, Chevron had a total of 20 company-operated double-hull tankers in operation. The company is a member of many oil-spill-response cooperatives in areas around the world in which it operates.

      Chevron Phillips Chemical Company LLC (CPChem) is equally owned with ConocoPhillips Corporation. CPChem owns or has joint venture interests in 31 manufacturing facilities and six research and technical centers in the United States, Puerto Rico, Belgium, China, Mexico, Saudi Arabia, Singapore, South Korea and Qatar.

      In 2005, construction progressed on CPChem’s integrated, world-scale styrene facility in Al Jubail, Saudi Arabia. Jointly owned with the Saudi Industrial Investment Group (SIIG), the project’s operationalstart-up is anticipated in late 2007. CPChem and SIIG currently operate an aromatics complex in Al Jubail.

      In the fourth quarter 2005, CPChem approved the continued development of plans for a third petrochemical project in Saudi Arabia. Preliminary studies are focused on the construction of a world-scale olefins unit, as well as downstream units, to produce polyethylene, polypropylene, 1-hexene and polystyrene. This project would capitalize on CPChem’s proven technologies and be located in Al Jubail, next to CPChem and SIIG’s existing aromatics complex and the styrene facility currently under construction. Final approval of the project is expected in 2007.

      Also during 2005, approvals were obtained and financial closing completed for the Q-Chem II project, which will include a350,000-metric-ton-per-year polyethylene plant and a345,000-metric-ton-per-year normal alpha olefins plant — each utilizing CPChem proprietary technology — located adjacent to the existing Q-Chem I complex in

Mesaieed, Qatar. The Q-Chem II project also includes a separate joint venture to develop a1,300,000-metric-ton-per-year ethylene cracker at Qatar’s Ras Laffan Industrial City, in which Q-Chem II owns 54 percent of the capacity rights. CPChem and its partners expect to start up the cracker and derivatives plants in late 2008. CPChem owns a 49 percent interest of Q-Chem II.

      Chevron’s Oronite brand fuel and lubricant additives business is a leading developer, manufacturer and marketer of performance additives for fuels and lubricating oils. The company owns and operates facilities in the United States, Brazil, France, the Netherlands, Singapore and Japan and has equity interests in facilities in India and Mexico. The previously announced decision to close the manufacturing plant in Brazil was reversed in 2005 due to increased worldwide demand for additives.

      Oronite provides additives for lubricating oil in most engine applications, such as passenger car, heavy-duty diesel, marine, two-cycle and railroad engines, and additives for fuels to improve engine performance and extend engine life.

      The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated two surface mines, McKinley, in New Mexico, and Kemmerer, in Wyoming, and one underground mine, North River, in Alabama, at year-end 2005. Final reclamation activities were completed at the York Canyon surface mine located in New Mexico, and reclamation activities continued in 2006 at the Farco surface mine in Texas. Chevron sold its 30 percent interest in Inter-American Coal Holding N.V. in late 2005. Sales of coal from P&M’s wholly owned mines and from its affiliates were 14.1 million tons, relatively unchanged from 2004.

      At year-end 2005, P&M controlled approximately 235 million tons of developed and undeveloped coal reserves in the United States, including reserves of environmentally desirable low-sulfur coal. The company is contractually committed to deliver approximately 14 million tons of coal per year through the end of 2006 and believes it will satisfy these contracts from existing coal reserves.

      The company acquired Molycorp Inc., which mines and markets molybdenum and rare earth minerals, as part of the Unocal acquisition. At year-end 2005, Molycorp owned and operated the Questa molybdenum mine in New Mexico and the Mountain Pass lanthanides mine in California. In addition, Molycorp owns a 35 percent interest in Companhia Brasileira de Metalurgia e Mineracao, a producer of niobium in Brazil, and a 33 percent interest in Sumikin Molycorp, a manufacturer of neodymium compounds, located in Japan. During 2005, Molycorp performed environmental remediation activities at Questa, New Mexico and Mountain Pass, California, and closed certain operations in Colorado and Pennsylvania.

      At year-end 2005, Molycorp controlled approximately 53 million pounds of developed and undeveloped molybdenum reserves at Questa and 241 million pounds of lanthanide reserves at Mountain Pass. Molycorp’s share of niobium reserves totaled 1.9 million tons.

      Also as part of the Unocal acquisition, the company acquired the Chicago Carbon Company that operates a250,000-ton-per-year petroleum coke calciner facility in Illinois.

      In Canada, Chevron holds a 20 percent nonoperated interest in the Athabasca Oil Sands Project (AOSP). Bitumen is extracted from oil sands and upgraded into synthetic crude oil using hydroprocessing technology. The integrated operation at AOSP commenced in 2003 withramp-up of production substantially completed in 2005. Total 2005 bitumen production averaged 158,000 barrels per day (about 32,000 net barrels). Net proved oil sands reserves at the end of 2005 were 146 million barrels.

      In early 2006, the company was evaluating feasibility of a proposed AOSP expansion. The expansion would be designed to produce approximately 100,000 barrels of bitumen per day (20,000 net barrels) and upgrade it into synthetic crude oil. If the AOSP expansion project proceeds, first production is expected in late 2009. No proved oil sands reserves have been recorded in association with this expansion.

      Chevron’s Global Power Generation (GPG) business has more than 20 years experience in developing and operating commercial power projects and owns 16 power assets located in the United States and Asia. GPG manages the production of more than 3,500 megawatts of electricity at 13 facilities it owns through joint ventures. The company operates gas-fired cogeneration facilities that use waste heat recovery to produce additional electricity or to support industrial thermal hosts. A number of the facilities produce steam for use in upstream operations to facilitate production of heavy oil.

      In 2005, the company acquired an additional 13 percent in the Tri Energy Company, a 700-megawatt independent power producer located in Ratchaburi Province, Thailand, increasing Chevron’s total ownership to 50 percent.

Gas-to-Liquids

      The Sasol Chevron Global 50-50 Joint Venture was established in October 2000 to develop a worldwidegas-to-liquids (GTL) business. Through this venture, the company is engaged in discussions with Qatar Petroleum (QP) on a number of projects, which include the design, construction and operation of a base oils production facility downstream of the Sasol and QP Oryx GTL plant in Qatar, and evaluation of an expansion of the Oryx GTL foundation plant from 34,000 to 100,000 barrels per day.

      In Nigeria, the Chevron Nigeria Limited and the Nigerian National Petroleum Corporation are developing a 34,000-barrel-per-day GTL facility at Escravos that will process natural gas supplied from the output of the Phase 3 expansion of the Escravos Gas Plant (EGP). The $1.7 billion engineering, procurement and construction contract was awarded in April 2005. Plant construction began in 2005, including major equipment fabrication and site preparation. Refer also to page 16 for a discussion on the EGP Phase 3 expansion.

      Chevron Energy Solutions (CES) is a wholly owned subsidiary that provides public institutions and businesses with projects that are designed to increase energy efficiency, reduce energy costs and ensure reliable, high-quality power for critical operations. CES has offices in the United States and has energy-saving projects installed in more than a thousand buildings nationwide.

      The company’s Energy Technology Company delivers integrated technologies and services to the upstream, downstream and gas-based businesses. These activities include exploration and production systems, reservoir management and optimization, heavy oil recovery and upgrading,gas-to-liquids processing, improved refining processes, safe, incident-free plant operations, and technical computing. The Information Technology Company provides a standardized digital infrastructure as well as information management and security for the company’s global operations.

      Chevron’s Technology Ventures Company (CTV) identifies, grows and commercializes emerging technologies that have the potential to transform how energy is produced or consumed. CTV’s activities range from early-stage investing of venture capital in emerging technologies to developing joint venture companies in new energy systems, such as hydrogen infrastructure, advanced batteries, nano-materials and renewable energy applications.

      Chevron’s research and development expenses were $316 million, $242 million and $228 million for the years 2005, 2004 and 2003, respectively.

      Because some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, ultimate success is not certain. Although not all initiatives may prove to be economically viable, the company’s overall investment in this area is not significant to the company’s consolidated financial position.

      Virtually all aspects of the company’s businesses are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to change and increase in both number

and complexity and to govern not only the manner in which the company conducts its operations, but also the products it sells. Chevron expects more environmental-related regulations in the countries where it has operations. Most of the costs of complying with the many laws and regulations pertaining to its operations are embedded in the normal costs of conducting business.

      In 2005, the company’s U.S. capitalized environmental expenditures were $227 million, which includes $2 million for Unocal activities for the last five months of 2005 and which represents approximately 6 percent of the company’s total consolidated U.S. capital and exploratory expenditures. These environmental expenditures include capital outlays to retrofit existing facilities, as well as those associated with new facilities. The expenditures are predominantly in the upstream and downstream segments and relate mostly to air- and water-quality projects and activities at the company’s refineries, oil and gas producing facilities, and marketing facilities. For 2006, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $452 million. The future annual capital costs of fulfilling this commitment are uncertain and will be governed by several factors, including future changes to regulatory requirements.

      Further information on environmental matters and their impact on Chevron and on the company’s 2005 environmental expenditures, remediation provisions and year-end environmental reserves are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages FS-18 toFS-19, and on pageFS-21 toFS-22 of this Annual Report on Form 10-K.

      The company’s Internet Web site can be found athttp://www.chevron.com/. Information contained on the company’s Internet Web site is not part of this Annual Report on Form 10-K.

      The company’s Annual Reports on Form 10-K,Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on the company’s Web site, free of charge, soon after such reports are filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s Internet Web site: http://www.sec.gov/.

      Chevron is a major fully integrated petroleum company with a diversified business portfolio, strong balance sheet, and a history of generating sufficient cash to fund capital and exploratory expenditures and to pay dividends. Nevertheless, some inherent risks could materially impact the company’s financial results of operations or financial condition.

      Chevron is primarily in a commodities business with a history of price volatility. The single largest variable that affects the company’s results of operations is crude oil prices. Except in the ordinary course of running an integrated petroleum business, Chevron does not seek to hedge its exposure to price changes. A significant, persistent decline in crude oil prices may have a material adverse effect on its results of operations and its capital and exploratory expenditure plans.

      The company is in an extractive business; therefore, if Chevron is not successful in replacing the crude oil and natural gas it produces with good prospects for future production, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining rights to explore, develop and produce hydrocarbons in promising areas, drilling success, ability to bring long lead-time, capital intensive projects to completion on budget and schedule, and efficient and profitable operation of mature properties.

      Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations and facilities are therefore subject to disruption from either natural or human causes, including hurricanes, earthquakes,

floods and other forms of severe weather, war, civil unrest and other political events, fires and explosions, any of which could result in suspension of operations, or harm to people or the natural environment.

      The company produces, transports, refines and markets materials with potential toxicity, and it purchases, handles and disposes of other potentially toxic materials in the course of the company’s business. Chevron operations also produce byproducts, which may be considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or as a result of new conclusions on the effects of the company’s operations on human health or the environment.

      The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by host governments to increase public ownership of the company’s partially- or wholly owned businesses, and/or to impose additional taxes or royalties.

      In certain locations, host governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a host government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results, and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2005, approximately 23 percent of the company’s proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC)-member countries including Indonesia, Nigeria and Venezuela. Approximately 22 percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2005.

      None.

      The location and character of the company’s crude oil, natural gas and coal properties and its refining, marketing, transportation and chemicals facilities are described above under Item 1. Business. Information required by the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas Operations”) is also contained in Item 1 and in Tables I through VII on pagesFS-65 toFS-78 of this Annual Report on Form 10-K.Note 14, “Properties, Plant and Equipment,” to the company’s financial statements is on pageFS-46 of this Annual Report on Form 10-K.

      The South Coast Air Quality Management District (AQMD) has issued several notices of violation to the Chevron Products Company, a division of Chevron U.S.A., Inc, alleging more than 160 violations of the AQMD’s Rule 463, which regulates emissions from floating roof tanks, at the company’s El Segundo, California, refinery, as previously reported in the company’s quarterly report on Form 10-Q for the period ended September 30, 2005. It was also noted that in August 2005, the AQMD contacted the company to ask that these violations be consolidated with a newly discovered matter involving alleged violations of the AQMD’s Rule 1173 concerning Leak Detection and Repair of components that emit volatile organic compounds. The company has settled these matters by agreeing to pay a civil penalty of $5 million and $1.5 million in emission fees.

      None.

      The Executive Officers of the Corporation consist of the Chairman of the Board, the Vice Chairman of the Board, and such other officers of the Corporation who are either Directors or members of the Executive Committee or who are chief executive officers of principal business units. Except as noted below, all of the Corporation’s Executive Officers have held one or more of such positions for more than five years.

      The information on Chevron’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-26 of this Annual Report on Form 10-K.